U.S. patent number 10,254,216 [Application Number 15/638,443] was granted by the patent office on 2019-04-09 for systems, methods and apparatus for analysis of reservoir fluids using surface plasmon resonance.
This patent grant is currently assigned to SCHLUMBERGER TECHNOLOGY CORPORATION. The grantee listed for this patent is SCHLUMBERGER TECHNOLOGY CORPORATION. Invention is credited to Kenneth John Chau, Shahnawaz Hossain Molla, Farshid Mostowfi, Vincent Joseph Sieben, Elizabeth Jennings Smythe.
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United States Patent |
10,254,216 |
Sieben , et al. |
April 9, 2019 |
Systems, methods and apparatus for analysis of reservoir fluids
using surface plasmon resonance
Abstract
An optical sensor includes a flow cell permitting flow of a
hydrocarbon-based analyte therethrough. A metallic film is disposed
adjacent or within the flow cell. At least one optical element
directs polychromatic light for supply to an interface of the
metallic film under conditions of surface plasmon resonance (SPR)
and directs polychromatic light reflected at the interface of the
metallic film (which is sensitive to SPR at such interface and thus
provides an SPR sensing region within the flow cell) for output to
at least one spectrometer that measures spectral data of such
polychromatic light. A computer processing system is configured to
process the measured spectral data over time as the
hydrocarbon-based analyte flows through the flow cell to determine
SPR peak wavelength over time and to process the SPR peak
wavelength over time to determine at least one property related to
phase transition of the analyte.
Inventors: |
Sieben; Vincent Joseph
(Cambridge, MA), Chau; Kenneth John (Kelowna, CA),
Molla; Shahnawaz Hossain (Watertown, MA), Mostowfi;
Farshid (Lexington, MA), Smythe; Elizabeth Jennings
(Cambridge, MA) |
Applicant: |
Name |
City |
State |
Country |
Type |
SCHLUMBERGER TECHNOLOGY CORPORATION |
Sugar Land |
TX |
US |
|
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Assignee: |
SCHLUMBERGER TECHNOLOGY
CORPORATION (Sugar Land, TX)
|
Family
ID: |
60806922 |
Appl.
No.: |
15/638,443 |
Filed: |
June 30, 2017 |
Prior Publication Data
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Document
Identifier |
Publication Date |
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US 20180003619 A1 |
Jan 4, 2018 |
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Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
Issue Date |
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62356868 |
Jun 30, 2016 |
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Current U.S.
Class: |
1/1 |
Current CPC
Class: |
G01N
21/05 (20130101); G01N 21/553 (20130101); G01N
33/2835 (20130101); G01N 21/27 (20130101); G01N
2021/258 (20130101) |
Current International
Class: |
G01N
21/05 (20060101); G01N 33/28 (20060101); G01N
21/27 (20060101); G01N 21/25 (20060101); G01N
21/552 (20140101) |
References Cited
[Referenced By]
U.S. Patent Documents
Other References
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Crystal Microbalance with Dissipation (QCM-D) under Flow
Conditions," Energy and Fuels, 23(3), 2009, pp. 1237-1248. cited by
applicant .
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Precipitation during C02 Injection", SPE 143903, presented at the
SPE Enhanced Oil Recovery Conference, Kuala Lumpur, Malaysia, 2011,
27 pages. cited by applicant .
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Modeling Wax Deposition in Fluid Flows. 1. Taylor-Couette System",
Industrial and Engineering Chemistry Research, 2008, 47(3), pp.
953-963. cited by applicant .
Akbarzadeh, K. et al., "The Importance of Wax-Deposition
Measurements in the Simulation and Design of Subsea Pipelines", SPE
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49-57. cited by applicant .
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Fuels, 2013, 27(2), pp. 752-759. cited by applicant .
Buckley, J.S., "Predicting the Onset of Asphaltene Precipitation
from Refractive Index Measurements", Energy & Fuels, 1999,
13(2), pp. 328-332. cited by applicant .
Buckley, J.S . et al., "Asphaltene Precipitation and Solvent
Properties of Crude Oils", Petroleum Science and Technology, 1998,
16(3-4), pp. 251-285. cited by applicant .
Gonzalez, D. L. et al., "Effects of Gas Additions to Deepwater Gulf
of Mexico Reservoir Oil: Experimental Investigation of Asphaltene
Precipitation and Deposition", SPE 159098, presented at the SPE
Annual Technical Conference and Exhibition, San Antonio, Texas,
USA, Society of Petroleum Engineers, 2012, 11 pages. cited by
applicant .
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Experimental Investigation of Onset Conditions and Reversibility",
Energy & Fuels, 1999, 14(1), p. 14-18. cited by applicant .
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Deposition", Energy & Fuels, 2011, 25(11), pp. 5180-5188. cited
by applicant .
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Techniques to Measure Thermodynamic Asphaltene Instability",
SPE-72154, presented at the SPE Asia Pacific Improved Oil Recovery
Conference, Kauala Lumpur, Malaysia, Society of Petroleum
Engineers, 2001, pp. 17 pages. cited by applicant .
Jamaluddin, A.K.M. et al., "An Investigation of Asphaltene
Instability Under Nitrogen Injection", SPE 74393, presented at the
SPE International Petroleum Conference and Exhibition,
Villahermosa, Mexico, Society of Petroleum Engineers Inc., 2012,
pp. 10 pages. cited by applicant .
Jorgenson, R. C. et al., "A fiber-optic chemical sensor based on
surface plasmon resonance", Sensors and Actuators: B. Chemical,
1993, 12(3), pp. 213-220. cited by applicant .
Jorgenson, R. C. et al., "Control of the dynamic range and
sensitivity of a surface plasmon resonance based fiber optic
sensor", Sensors and Actuators: A. Physical, 1994, 43(1-3), pp.
44-48. cited by applicant .
Joshi, N. B., et al., "Asphaltene Precipitation from Live Crude
Oil", Energy & Fuels, 2001, 15(4), pp. 979-986. cited by
applicant .
Kalantari-Dahaghi, A. et al., "Formation Damage Through Asphaltene
Precipitation Resulting From C02 Gas Injection in Iranian Carbonate
Reservoirs" SPE Production & Operations, 2008, 23(2), pp.
210-214. cited by applicant .
Mehfuz, R., "Improving the Excitation Efficiency of Surface Plasmon
Polaritons Near Small Apertures in Metallic Films", 2013, The
University of British Columbia: Okanagan, 140 pages. cited by
applicant .
Milhet M. et al., "Liquid-solid equilibria under high pressure of
tetradecane + pentadecane and tetradecane + hexadecane binary
systems", Fluid Phase Equilibria, 2005, 235(2), pp. 173-181. cited
by applicant .
Ooms, M. D. et al., "Surface Plasmon Resonance for Crude Oil
Characterization", Energy & Fuels, 2015, 29(5), pp. 3019-3023.
cited by applicant .
Reimhult, E. et al., "Simultaneous Surface Plasmon Resonance and
Quartz Crystal Microbalance with Dissipation Monitoring
Measurements of Biomolecular Adsorption Events Involving Structural
Transformations and Variations in Coupled Water", Analytical
Chemistry, 2004, 76(24), pp. 7211-7220. cited by applicant .
Sarica, C. et al., "Review of Paraffin Deposition Research under
Multiphase Flow Conditions", Energy & Fuels, 2012, 26(7), pp.
3968-3978. cited by applicant .
Schneider, M.H. et al., "Measurement of Asphaltenes Using Optical
Spectroscopy on a Microfluidic Platform", Analytical Chemistry,
2013, 85(10), pp. 5153-5160. cited by applicant .
Skinner, N. G. et al. "Downhole fiber optic sensing: the oilfield
service provider's perspective: from the cradle to the grave",
Proc. SPIE 9098, Fiber Optic Sensors and Applications, 2014, 18
pages. cited by applicant .
Takagi, T. et al., "Refractive Index of Liquids under High
Pressure", Journal of Chemical & Engineering Data, 1982, 27(1),
pp. 16-18. cited by applicant .
Tvakkoli, M. et al., "Asphaltene Deposition in Different Depositing
Environments: Part 2. Real Oil," Energy & Fuels, 2014, 28(6),
pp. 3594-3603. cited by applicant .
Tvakkoli, M. et al., "Asphaltene Deposition in Different Depositing
Environments: Part 1. Model Oil", Energy & Fuels, 2014, 28(3),
pp. 1617-1628. cited by applicant .
Wang, J. et al., "Asphaltene Deposition on Metallic Surfaces,"
Journal of Dispersion Science and Technology, 2004, 25(3), pp.
287-298. cited by applicant .
"Standard Test Method for Determinatoin of Asphaltenes (Heptane
Insolubles) in Crude Petroleum and Petroleum Products", ASTM D6560,
2005, 6 pages. cited by applicant.
|
Primary Examiner: Decenzo; Shawn
Parent Case Text
CROSS-REFERENCE TO RELATED APPLICATION(S)
The present disclosure claims priority from U.S. Provisional Patent
Appl. No. 62/356,868, filed on Jun. 30, 2016, herein incorporated
by reference in its entirety.
Claims
What is claimed is:
1. An optical sensor comprising: a flow cell that is configured to
permit flow of a hydrocarbon-based analyte through the flow cell; a
metallic film disposed adjacent or within the flow cell; a light
source configured to generate polychromatic light; at least one
optical element configured to direct polychromatic light produced
by the light source for supply to an interface of the metallic film
under conditions of surface plasmon resonance and to direct
polychromatic light reflected at the interface of the metallic film
for output from the at least one optical element, wherein the
polychromatic light reflected at the interface of the metallic film
is sensitive to surface plasmon resonance at the interface of the
metallic film in order to provide an surface plasmon resonance
(SPR) sensing region within the flow cell; at least one
spectrometer operably coupled to the at least one optical element,
wherein the at least one spectrometer is configured to measure
spectral data of polychromatic light reflected at the interface of
the metallic film as output by the least one optical element; and a
computer processing system operably coupled to the at least one
spectrometer, wherein the computer processing system is configured
to process the spectral data measured by the at least one
spectrometer over time as the hydrocarbon-based analyte flows
through the flow cell to determine SPR peak wavelength over time,
and wherein the computer processing system processes the SPR peak
wavelength over time to determine at least one property related to
phase transition of the hydrocarbon-based analyte.
2. An optical sensor according to claim 1, wherein: the at least
one optical element comprises a prism disposed adjacent the
metallic film.
3. An optical sensor according to claim 2, wherein: the prism
comprises a dove prism.
4. An optical sensor according to claim 2, wherein: the metallic
film is part of a multilayer structure formed on one side of a
substrate, wherein the multilayer structure interfaces to the flow
cell and the opposite side of the substrate is disposed adjacent
the prism.
5. An optical sensor according to claim 4, further comprising: an
index matching fluid disposed between the opposite side of the
substrate and the prism.
6. An optical sensor according to claim 1, wherein: the least one
optical element comprises a fiber optic core, wherein the metallic
film is bonded to the fiber optic core.
7. An optical sensor according to claim 6, wherein: the metallic
film is part of a multilayer structure bonded to the fiber optic
core.
8. An optical sensor according to claim 7, wherein: the multilayer
structure surrounds a lengthwise segment of the fiber optic core;
and the lengthwise segment of the fiber optic core directs
polychromatic light to the metallic film of the surrounding
multilayer structure for reflection at the interface of the
metallic film of the surrounding multilayer structure.
9. An optical sensor according to claim 8, wherein: the least one
optical element further comprises a mirror formed at one end of the
fiber optic core, wherein the mirror is configured to return
polychromatic light reflected at the interface of the metallic film
of the surrounding multilayer structure for output to a
spectrometer.
10. An optical sensor according to claim 9, wherein: the mirror is
formed from the same metal as the metallic film of the multilayer
structure.
11. An optical sensor according to claim 8, wherein: the fiber
optic core is configured to transmit polychromatic light reflected
at the interface of the metallic film of the surrounding multilayer
structure for output to a spectrometer.
12. An optical sensor according to claim 6, wherein: the fiber
optic core and metallic film are part of a probe assembly that
extends into the flow cell.
13. An optical sensor according to claim 12, wherein: the probe
assembly extends into the flow cell in a direction parallel to the
flow through the flow cell.
14. An optical sensor according to claim 12, wherein: the probe
assembly extends into the flow cell in a direction transverse to
the flow through the flow cell.
15. An optical sensor according to claim 12, further comprising: a
seal that provides a fluid seal between the probe assembly and the
flow cell.
16. An optical sensor according to claim 1, wherein: the metallic
film is part of a multilayer structure that interfaces to the flow
cell or that extends into the flow cell.
17. An optical sensor according to claim 1, wherein: the multilayer
structure includes a thin-film stack including a protective layer
that covers the metallic film and/or a bonding layer formed under
the metallic film.
18. An optical sensor according to claim 17, wherein: the
protective layer is present and comprises Zirconium Dioxide.
19. An optical sensor according to claim 17, wherein: the bonding
layer is present and comprises Titanium.
20. An optical sensor according to claim 1, wherein: the metallic
film comprises gold or silver.
21. An optical sensor according to claim 1, further comprising: a
polarizer coupled to the at least one optical element, wherein the
polarizer is configured to split polychromatic light reflected at
the interface of the metallic film into an s-polarized beam and a
p-polarized beam.
22. An optical sensor according to claim 21, wherein: the at least
one spectrometer comprise a first spectrometer and a second
spectrometer, the first spectrometer configured to measure spectral
data of the s-polarized beam, and the second spectrometer
configured to measure spectral data of the p-polarized beam; and
the computer processing system is operably coupled to the first and
second spectrometers and is configured to determine an absorbance
spectrum for a given time interval by subtracting spectral data of
the s-polarized beam from spectral data of the p-polarized
beam.
23. An optical sensor according to claim 22, wherein: the computer
processing system is configured to identify a peak in the
absorbance spectrum over time in order to determine the SPR peak
wavelength over time.
24. An optical sensor according to claim 1, further comprising: a
fiber splitter that directs polychromatic light produced by the
light source for supply to the interface of the metallic film.
25. An optical sensor according to claim 24, wherein: the fiber
splitter directs polychromatic light produced by the light source
to a first spectrometer; and the fiber splitter directs
polychromatic light reflected at the interface of the metallic film
for output to a second spectrometer.
26. An optical sensor according to claim 25, wherein: the computer
processing system is configured to determine an absorbance spectrum
for a given time interval by subtracting spectral data determined
by measurements of the first spectrometer from spectral data
determined by measurements of the second spectrometer.
27. An optical sensor according to claim 26, wherein: the computer
processing system is configured to identify a peak in the
absorbance spectrum over time in order to determine the SPR peak
wavelength over time.
28. An optical sensor according to claim 1, wherein: the
hydrocarbon-based analyte is mixture of an asphaltene precipitant
and crude oil with varying volume fractions of asphaltene
precipitant over time; and the at least one property related to
phase transition of the hydrocarbon-based analyte characterizes
asphaltene deposition onset of the crude oil.
29. An optical sensor according to claim 1, wherein: the computer
processing system is further configured to employ a model that
relates SPR peak wavelength to a refractive index of the crude
oil.
30. An optical sensor according to claim 29, wherein: the model is
calibrated by experiments with mixtures of an asphaltene
precipitant and asphaltene solvent at different relative volume
fractions such that SPR peak wavelengths produced by the model
matches measured SPR peak wavelengths determined by the computer
processing system.
31. An optical sensor according to claim 29, wherein: the computer
processing system is further configured to employ a correlation
function that relates the refractive index of the crude oil to a
density of the crude oil.
32. An optical sensor according to claim 1, wherein the at least
one property related to phase transition of the hydrocarbon-based
analyte is associated with at least one of: i) detection of the
formation of vapor or liquid phases of the hydrocarbon-based
analyte induced by temperature and/or pressure changes; ii)
detection of liquid condensation from hydrocarbon vapors induced by
temperature and/or pressure changes; iii) detection of hydrate
formation induced by temperature and/or pressure changes; iv)
detection of scaling or inorganic precipitation induced by
composition, temperature and/or pressure changes; v) detection of
asphaltene onset induced by composition, temperature and/or
pressure or changes; and vi) sample fluid typing by means of
measuring the direction and/or magnitude of the SPR shift when
undergoing phase change.
33. An optical sensor according to claim 1, further comprising: a
pressure control system for controlling pressure of the
hydrocarbon-based analyte flowing through the flow cell over
time.
34. An optical sensor according to claim 33, wherein: the pressure
control system is configured to vary pressure conditions of the
hydrocarbon-based analyte flowing through the flow cell over one or
more time intervals.
35. An optical sensor according to claim 33, wherein: the pressure
control system is configured to maintain constant pressure
conditions of the hydrocarbon-based analyte flowing through the
flow cell over one or more time intervals.
36. An optical sensor according to claim 1, further comprising: a
temperature control system for controlling temperature of the
hydrocarbon-based analyte flowing through the flow cell over
time.
37. An optical sensor according to claim 36, wherein: the
temperature control system is configured to vary temperature
conditions of the hydrocarbon-based analyte flowing through the
flow cell over one or more time intervals.
38. An optical sensor according to claim 36, wherein: the
temperature control system is configured to maintain constant
temperature pressure conditions of the hydrocarbon-based analyte
flowing through the flow cell over one or more time intervals.
Description
TECHNICAL FIELD
The present disclosure relates to methods and systems and apparatus
that analyze reservoir fluids using surface plasmon resonance.
BACKGROUND
Asphaltenes are a sub-component of crude oil that form sticky
aggregates when a shift in the native solubility matrix is caused
by a change in pressure, temperature, or composition of the oil.
The thermodynamics of asphaltene stability, the mechanisms of
agglomeration, and the models for deposition are the focus of
intense and active areas of research.
Unintended precipitation and deposition of asphaltene from
reservoir fluids can happen during production, transportation, and
processing operations. These deposits can lead to reservoir
impairment, plugging near the wellbore, restriction in flowlines,
as well as equipment failures and processing challenges for surface
facilities. As such, flow assurance that accounts for possible
precipitation and deposition of asphaltene from reservoir fluid
relies heavily on frequent and accurate measurements, particularly
when characterizing the asphaltene phase behavior within a crude
sample.
Asphaltenes of a crude oil are conventionally defined as being
poorly soluble in n-alkanes (e.g., n-heptane) and highly soluble in
aromatic solvents (e.g., toluene). With this broad definition, the
asphaltenes are a fraction of a crude oil sample that can vary from
one crude oil sample to another. The complex mixture of asphaltene
molecules can be characterized with a distribution of varying
solubility parameters; ranging from the least soluble (less stable
asphaltenes) to the most soluble (more stable asphaltenes). Gradual
titration of stock tank crude oil or gradual depressurization of
live crude oil is most often used to measure the solubility profile
of the asphaltene fraction. The proportional amount of asphaltene
precipitation can be measured by controllably sweeping the level of
perturbation to the native crude oil. This profile can then be
related to flow assurance control schemes and models. For example,
as the amount of n-alkane (or titrant) is varied, only a fraction
of the total amount of asphaltene precipitates. The remainder of
asphaltenes stay in solution due to partial solubility. An
asphaltene yield curve can be created by scanning a range of
titrant-oil fractions, which is a plot relating the amount of
precipitated asphaltenes as a function of titrant concentration.
The data contained in the yield curve is related to asphaltene
solubility or the phase separation of asphaltenes. Key parameters,
like the asphaltenes precipitation onset point, can be extracted
from such titration curves.
There are a number of techniques used to detect and measure the
extent of asphaltene precipitation, including: visual observation,
absorption and fluorescence spectroscopy, light scattering,
refractive index-based methods, conductivity, acoustic resonance
and filtration methods, viscosity, and the conventional gravimetric
approach.
Currently, the asphaltene onset condition (pressure, temperature,
and composition) in crude oil is determined by systematic
depressurization (at constant temperature) of a sample of the crude
oil in a PVT cell in the laboratory. In the PVT cell, precipitation
of asphaltene is detected based on visual observation and light
scattering. Another approach for detecting the onset of asphaltene
precipitation and yield is to measure the crude oil refractive
index during temperature, pressure, or composition perturbations.
Buckley, J. S., Predicting the Onset of Asphaltene Precipitation
from Refractive Index Measurements. Energy & Fuels, 1999,
13(2): p. 328-332 presents a graph of the measured refractive index
(RI) for a mixture of n-heptane and oil. The mixture RI gradually
decreases as n-heptane is added to a sample crude oil. When the
asphaltene onset condition is reached, the mixture RI sharply
decreases indicated by a difference in slopes. Sudden changes in RI
indicate a phase transition. Surface plasmon resonance (SPR)
spectra can also be used to determine the refractive index of the
sample, which in turn may be used to measure solubility parameters
of hydrocarbon fluids.
Furthermore, there are relatively few methods to monitor and
characterize asphaltene deposition in real-time. Most often, a
deposition experiment monitors the time-wise pressure change across
a capillary tube or porous media while flowing crude oil through
the system under specific conditions. The relative pressure change
is determined using the Hagen-Poiseuille equation, assuming uniform
deposition thickness on the wall surface along the entire flow-line
length. When relating deposit thickness to pressure drop, it is
further assumed that flow rate and viscosity remain constant. To
achieve the required sensitivity, multiple pressure transducers
with overlapping dynamic ranges are coupled to the entry port of a
long stainless steel tube. It is necessary to have long tube
lengths of 16-32 m with small cross-sections of 0.5 mm diameter and
slow flowrates of approximately 5 mL/hr as described in Wang et
al., "Asphaltene Deposition on Metallic Surfaces," Journal of
Dispersion Science and Technology, Vol. 25(3), 2004, pgs. 287-298.
Creating measurable deposits, 1-100 .mu.m, often takes 50-100 hours
or 2-4 days. Variations in deposition thickness, e.g. constricted
regions or plugs, are not easily measured and detrimentally impact
the apparent deposition thickness. Gradation can be accomplished
with multiple sensor ports incorporated into the flow-line, but
this creates added dead-volume and geometry changes at each
pressure transducer junction. With flowline deposition experiments,
one can also perform post-characterization of deposits in a
batch-like manner. At the conclusion of the run, the surfaces of a
Taylor-Couette device/chamber, or segments of the flowline, are
rinsed with a solvent to capture the deposit, which is then
concentrated and measured gravimetrically. These methods are
excellent for detailed characterization of the deposit, but do not
provide online feedback as the deposit is formed. Flowline
deposition experiments therefore lack the sensitivity to observe
initial adsorbed asphaltene layers and require significant
runtimes.
Real-time observations of deposit formation have been made using a
Quartz Crystal Microbalance with Dissipation (QCM-D) as described
in Abudu et al., "Adsorption of Crude Oil on Surfaces Using Quartz
Crystal Microbalance with Dissipation (QCM-D) under Flow
Conditions," Energy and Fuels, Vol. 23(3), 2009, pgs. 1237-1248.
The QCM-D measurements can be performed during titration
experiments and achieve high mass sensitivity based on the
electromechanical response of an oscillating piezoelectric sensor.
Relating frequency shift and mass change in a vacuum or a gas
environment can be accomplished with the Sauerbrey equation. QCM in
a liquid environment like when immersed in crude oil is more
complicated. The frequency shift depends on the chamber pressure,
deposit mass loading (asphaltenes-viscoelastic films), liquid
loading, liquid trapping, and surface roughness. Decoupling the
deposited asphaltene mass from the other system attributes that
impact the frequency shift requires tuned models. Often, correction
factors and prior knowledge of the crude oil density and viscosity
are required. Tavakkoli et al. performed a two-part detailed study
of the factors influencing QCM-D measurements when coupled with
titration experiments. See Tavakkoli et al., "Asphaltene Deposition
in Different Depositing Environments: Part 1. Model Oil", Energy
& Fuels, Vol. 28(3), 2014, pgs. 1617-1628; and Tavakkoli et
al., "Asphaltene Deposition in Different Depositing Environments:
Part 2. Real Oil," Energy & Fuels, Vol. 28(6), 2014, pgs.
3594-3603. They also evaluated deposition tendency using crystal
surfaces coated with a variety of materials, including: gold,
carbon steel, and iron oxide. Their work highlights the key
advantages of QCM-D, namely: the sensitivity to detect nanograms of
adsorbed mass, the ability to select relevant surface coatings, and
fast measurement times (.about.hours). However, online QCM sensing
of the deposit formation during flow conditions requires real-time
thin-film density information to decouple entrapped fluid mass from
asphaltene deposit mass. To solve a similar problem, Reimhult et
al. combined QCM-D with surface plasmon resonance (SPR) to
simultaneously measure the mass reported by both methods for an
aqueous biomolecular system as described in Reimhult et al.,
"Simultaneous surface plasmon resonance and quartz crystal
microbalance with dissipation monitoring measurements of
biomolecular adsorption events involving structural transformations
and variations in coupled water," Analytical Chemistry, Vol.
76(24), 2004, pgs. 7211-7220. QCM-D data was used to determine the
total adsorbed thin-film mass (acoustically derived), while SPR
data was used to determine the adsorbed biomolecule mass (optically
derived) via refractive index of the thin-film decoupled from
dynamically bound water. Reimhult et al. employed an iterative
calculation process that incorporated physical models of the
QCM-D/SPR approaches and determined accurate thin-film properties:
thickness, density, total mass, water mass, and biomolecular mass.
Lastly, realizing QCM-D devices at reservoir pressures that range
from 5-30 kpsi will be challenging as most demonstrations with
crude oil fluids are performed near atmospheric pressure. Studies
show that it is feasible to build QCM systems rated to 3 kpsi, but
thus far, the technique is generally limited to 5-6 kpsi.
SUMMARY
This summary is provided to introduce a selection of concepts that
are further described below in the detailed description. This
summary is not intended to identify key or essential features of
the claimed subject matter, nor is it intended to be used as an aid
in limiting the scope of the claimed subject matter.
In accordance with some examples, a novel optical sensor is
provided that includes a flow cell that is configured to permit
flow of a hydrocarbon-based analyte through the flow cell. A
metallic film is disposed adjacent or within the flow cell. A light
source is configured to generate polychromatic light. At least one
optical element is configured to direct polychromatic light
produced by the light source for supply to an interface of the
metallic film under conditions of surface plasmon resonance and to
direct polychromatic light reflected at the interface of the
metallic film for output from the at least one optical element. The
polychromatic light reflected at the interface of the metallic film
is sensitive to surface plasmon resonance at the interface of the
metallic film in order to provide an SPR sensing region within the
flow cell. At least one spectrometer is operably coupled to the at
least one optical element and is configured to measure spectral
data of polychromatic light reflected at the interface of the
metallic film as output by the least one optical element. A
computer processing system is operably coupled to the at least one
spectrometer and is configured to process the spectral data
measured by the at least one spectrometer over time as the
hydrocarbon-based analyte flows through the flow cell to determine
SPR peak wavelength over time, and to process the SPR peak
wavelength over time to determine at least one property related to
phase transition of the hydrocarbon-based analyte.
In embodiments, the at least one optical element can include a
prism (such as dove prism) disposed adjacent the metallic film can
be part of a multilayer structure formed on one side of a
substrate, wherein the multilayer structure interfaces to the flow
cell and the opposite side of the substrate is disposed adjacent
the prism. An index matching fluid can be disposed between the
opposite side of the substrate and the prism.
In other embodiments, the least one optical element can include a
fiber optic core with the metallic film bonded to the fiber optic
core. The metallic film can be part of a multilayer structure
bonded to the fiber optic core. The multilayer structure can
surround a lengthwise segment of the fiber optic core, and the
lengthwise segment of the fiber optic core can direct polychromatic
light to the metallic film of the surrounding multilayer structure
for reflection at the interface of the metallic film of the
surrounding multilayer structure.
In embodiments, the least one optical element can further include a
mirror formed at one end of the fiber optic core, wherein the
mirror is configured to return polychromatic light reflected at the
interface of the metallic film of the surrounding multilayer
structure for output to a spectrometer. The mirror can be formed
from the same metal as the metallic film of the multilayer
structure.
In other embodiments, the fiber optic core can be configured to
transmit polychromatic light reflected at the interface of the
metallic film of the surrounding multilayer structure for output to
a spectrometer.
In embodiment(s), the fiber optic core and metallic film (or the
surrounding multilayer structure including the metallic film) can
be part of a probe assembly that extends into the flow cell. The
probe assembly can extend into the flow cell in a direction
parallel to the flow through the flow cell, or in a direction
transverse to the flow through the flow cell. A seal can provide a
fluid seal between the probe assembly and the flow cell.
In embodiment(s), the metallic film can be part of a multilayer
structure that interfaces to the flow cell or that extends into the
flow cell. The multilayer structure can include a thin-film stack
including a protective layer (e.g., Zirconium Dioxide) that covers
the metallic film and/or a bonding layer (e.g., Titanium) formed
under the metallic film. The metallic film can be gold or
silver.
In embodiment(s), the optical sensor can include a polarizer
coupled to the at least one optical element, wherein the polarizer
is configured to split polychromatic light reflected at the
interface of the metallic film into an s-polarized beam and a
p-polarized beam. The at least one spectrometer can include a first
spectrometer and a second spectrometer, wherein the first
spectrometer is configured to measure spectral data of the
s-polarized beam, and the second spectrometer is configured to
measure spectral data of the p-polarized beam. The computer
processing system can be operably coupled to the first and second
spectrometers and can be configured to determine an absorbance
spectrum for a given time interval by subtracting spectral data of
the s-polarized beam from spectral data of the p-polarized beam.
The computer processing system can be further configured to
identify a peak in the absorbance spectrum over time in order to
determine the SPR peak wavelength over time.
In other embodiment(s), the optical sensor can include a fiber
splitter that directs polychromatic light produced by the light
source for supply to the interface of the metallic film. The fiber
splitter can be configured to direct polychromatic light produced
by the light source to a first spectrometer and direct
polychromatic light reflected at the interface of the metallic film
for output to a second spectrometer. The computer processing system
can be configured to determine an absorbance spectrum for a given
time interval by subtracting spectral data determined by the
measurements of the first spectrometer from spectral data
determined by the measurements of the second spectrometer. The
computer processing system can be further configured to identify a
peak in the absorbance spectrum over time in order to determine the
SPR peak wavelength over time.
In embodiment(s), the hydrocarbon-based analyte can be mixture of
an asphaltene precipitant (e.g., n-heptane) and crude oil with
varying volume fractions of the asphaltene precipitant over time,
and the at least one property related to phase transition of the
hydrocarbon-based analyte can characterize asphaltene deposition
onset of the crude oil. The computer processing system can be
further configured to employ a model that relates SPR peak
wavelength to a refractive index of the crude oil. The model can be
calibrated by experiments with mixtures of the asphaltene
precipitant (e.g., n-heptane) and an asphaltene solvent (e.g.,
toluene) at different relative volume fractions such that SPR peak
wavelengths produced by the model matches measured SPR peak
wavelengths determined by the computer processing system. The
computer processing system can be further configured to employ a
correlation function that relates the refractive index of the crude
oil to a density of the crude oil.
In embodiment(s), the property related to phase transition of the
hydrocarbon-based analyte can be associated with at least one
of:
i) detection of the formation of vapor or liquid phases of the
hydrocarbon-based analyte induced by temperature and/or pressure
changes;
ii) detection of liquid condensation from hydrocarbon vapors
induced by temperature and/or pressure changes;
iii) detection of hydrate formation induced by temperature and/or
pressure changes;
iv) detection of scaling or inorganic precipitation induced by
composition, temperature and/or pressure changes;
v) detection of asphaltene onset induced by composition,
temperature and/or pressure or changes; and
vi) sample fluid typing by means of measuring the direction and/or
magnitude of the SPR shift when undergoing phase change.
In embodiment(s) the optical sensor can include a pressure control
system for controlling pressure of the hydrocarbon-based analyte
flowing through the flow cell over time. The pressure control
system can be configured to vary pressure conditions of the
hydrocarbon-based analyte flowing through the flow cell over one or
more time intervals, or configured to maintain constant pressure
conditions of the hydrocarbon-based analyte flowing through the
flow cell over one or more time intervals. The optical sensor can
further include a temperature control system for controlling
temperature of the hydrocarbon-based analyte flowing through the
flow cell over time. The temperature control system can be
configured to vary temperature conditions of the hydrocarbon-based
analyte flowing through the flow cell over one or more time
intervals, or maintain constant temperature pressure conditions of
the hydrocarbon-based analyte flowing through the flow cell over
one or more time intervals.
In embodiment(s), the optical sensor can be part of a downhole
tool.
In other embodiment(s), the optical sensor can be part of
surface-located equipment at a well-site, fluid collection system,
fluid processing system, or pipeline.
In still other embodiment, the optical sensor can be part of a
laboratory apparatus.
BRIEF DESCRIPTION OF THE DRAWINGS
Those skilled in the art should more fully appreciate advantages of
various embodiments of the present disclosure from the following
"Description of Illustrative Embodiments," discussed with reference
to the drawings summarized immediately below.
FIG. 1 is a schematic illustration of surface plasmon resonance
(SPR) sensor according to the present disclosure.
FIG. 2A is a schematic illustration of a titration experiment
carried out with the SPR sensor of FIG. 1 in order to measure
asphaltene deposition onset of a crude oil or other hydrocarbon
bearing fluid.
FIG. 2B is a flowchart of a workflow of the titration experiment of
FIG. 2A.
FIG. 3A are plots of the spectra measured by the spectrometers of
the SPR sensor of FIG. 1 as part of an exemplary stepwise titration
experiment following the workflow of FIG. 2B.
FIG. 3B is a plot of SPR weak wavelength over time, which is
determined by the SPR sensor of FIG. 1 as part of the exemplary
stepwise titration experiment of FIG. 3A.
FIG. 4A are plots of SPR weak wavelength over time, which is
determined by the SPR sensor of FIG. 1 as part of a ramped
titration experiment on three different crude oils.
FIG. 4B are plots of SPR weak wavelength versus n-heptane:oil
volume fraction, which is determined by the SPR sensor of FIG. 1 as
part of the ramped titration experiment on three different crude
oils of FIG. 4A.
FIG. 5 are plots of exemplary SPR absorbance spectra, which is
determined by the SPR sensor of FIG. 1 as part of the titration
experiment at various n-heptane:oil volume ratios for a crude oil
sample along with schematic diagrams of a proposed asphaltene
deposition mechanisms for the four-stages of the titration
experiment.
FIG. 6 are plots of SPR peak wavelength versus n-heptane:oil volume
fraction for the fluid and the deposit, which is determined by the
SPR sensor of FIG. 1 as part of the titration experiment for the
crude oil sample of FIG. 5 where the spectral data is analyzed with
a two-peak model function.
FIGS. 7A to 7E illustrate example embodiments that employ a
reflective-type SPR sensor probe.
FIGS. 8A to 8C illustrate example embodiments that employ a
transmissive-type SPR sensor probe.
FIG. 9 shows a fluid analysis platform using an SPR sensor probe
(labeled "SPR detector) and associated sample handling, pressure
and temperature control system, which employs preset isothermal
conditions for all blocks.
FIG. 10 shows a fluid analysis platform using an SPR sensor probe
(labeled "SPR detector) and associated sample handling, pressure
and temperature control system, which employs filtration and
isothermal conditions for all blocks.
FIG. 11 is a flowchart of a workflow for detecting phase change of
a reservoir fluid sample using an SPR sensor probe and associated
sample handling, pressure and temperature control system.
FIG. 12 is a schematic diagram of a laboratory apparatus with an
SPR sensor probe.
FIG. 13 is a schematic diagram of a downhole tool system with two
SPR sensor probes.
FIGS. 14A, 14C and 14E are graphs that show the reflected or
transmitted spectra (labeled "collected light) and the reference
spectra (labeled "input light") as measured by the spectrometers of
the SPR sensing systems of FIG. 7A or 8A for a reservoir fluid
sample that is experiencing phase change. FIGS. 14B, 14D and 14F
show the corresponding change in SPR peak wavelength determined by
the SPR sensing systems of FIG. 7A or 8A based on analysis of the
reflected or transmitted spectra and the reference spectra for the
reservoir fluid sample that is experiencing phase change.
FIG. 15 is a phase diagram of a gas condensate, showing phase
boundaries and conditions under which multiple phases can coexist
at equilibrium.
FIG. 16 is a schematic diagram showing one example of a rig on
which disclosed downhole tool embodiments may be utilized.
FIG. 17 is a schematic fluid flow circuit diagram of the downhole
tool of FIG. 16 in which disclosed SPR sensor embodiments may be
utilized.
FIG. 18 is a schematic diagram showing one example of a production
well in which disclosed SPR sensor embodiments may be utilized.
FIG. 19 is a schematic block diagram of a computer processing
platform that can be used as part of the disclosed SPR sensor
embodiments.
DETAILED DESCRIPTION
Before the present invention is described in greater detail, it is
to be understood that aspects of the present disclosure are not
limited to the particular embodiments described, and as such may,
of course, vary. It is also to be understood that the terminology
used herein is for the purpose of describing particular embodiments
only, and is not intended to be limiting, since the scope of
embodiments of the present disclosure will be defined only by the
appended claims.
As will be apparent to those of skill in the art upon reading this
disclosure, each of the individual embodiments described and
illustrated herein has discrete components and features which may
be readily separated from or combined with the features of any of
the other several embodiments without departing from the scope or
spirit of the present invention. Any recited method can be carried
out in the order of events recited or in any other order which is
logically possible.
The term "surface plasmon resonance" or "SPR" as used herein
describes a condition in which light incident onto a surface of a
highly conductive metallic film couples into resonant charge
oscillations of the metallic film, resulting in light that is
effectively trapped to the surface of the metallic film. In this
trapped state, the light is sensitive to the dielectric environment
in the immediate vicinity of the opposite surface of the metallic
film (i.e., less than 1 .mu.m away from the opposite surface of the
metallic film). This condition is useful for detection of
properties of an analyte that is deposited or located in the
immediate vicinity of the opposite surface of the metallic
film.
A Surface Plasmon Resonance (SPR) sensor analyzes a fluid under a
condition in which light couples to charge oscillations at the
surface of a metal, where the probing field penetrates in the
immediate vicinity of the opposite surface of the metallic film
(i.e., less than 1 .mu.m away from the opposite surface of the
metallic film). When mass adheres to the surface of the metal, the
native thin-film resonant frequency shifts. SPR sensors are based
on the Kretschmann configuration in which polarized light is
directed by a high-index prism onto a thin metal film. A reduction
in the light intensity reflected from the metal film can be
interrogated by varying the angle of incidence of the light beam
onto the thin metal film.
In accordance with the present disclosure, an SPR sensor 101 as
shown in FIG. 1 is provided that avoids the utilization of moving
parts as is typically required by SPR sensors that vary the angle
of incidence of the light beam onto the thin metal film. The SPR
sensor 101 can possibly sacrifice resolution with readily available
spectrometers, but can provide faster acquisition times and is more
amenable to ruggedized applications, such as part of a downhole
tool that experiences high pressure high temperature conditions of
a downhole wellbore environment or as part of a surface-located
system at a wellsite or pipeline. The SPR sensor 101 includes a
polychromatic light source 103 (for example, the HL-2000 tungsten
halogen white light source 360-2400 nm commercially available from
Ocean Optics, USA) that is coupled to a collimator 105 (for
example, the F240SMA-B collimator commercially available from
Thorlabs, USA) using a light guide 107 (such as a 2 m long 0.22
NA-200 .mu.m core SMA-SMA M92L02 fiber patch cable commercially
available from Thorlabs, USA). The collimated beam produced by the
collimator 105 is then passed through an adjustable iris (not
shown) to produce a light beam 107 that is coupled to a prism 109.
In one embodiment, the prism 109 is a dove prism realized from
sapphire material. The prism can have a long side of 70.81 mm, a
width and height of 15 mm, a short side of 53.49 mm, and angled
faces at 600 to the long side, with a crystallographic orientation
where the c-plane is aligned to the 70.81.times.15 mm and
53.49.times.15 mm faces. The prism 109 directs the incident light
beam to a substrate 111 with a thin-film stack 113 formed on the
bottom-side of the substrate 111 as shown. An index matching fluid
(for example, refractive index-matching liquid 18152 commercially
available from Cargille, USA with a refractive index of 1.77) can
be disposed between the prism 109 and the substrate 111. In one
embodiment, the substrate 111 is formed of sapphire material and is
1 mm thick. The thin-film stack 113 includes a series of layers
formed on the substrate 111. In one embodiment, the series of
layers of the thin-film stack 113 includes a layer of Titanium (Ti)
of approximately 5 nm in thickness (adhesion layer), which is
formed below a layer of Gold (Au) of approximately 50 nm in
thickness (primary plasmonic layer), which is formed below a layer
of Zirconium dioxide (ZrO.sub.2) of approximately 15 nm in
thickness (protection layer). In other embodiments, Silver (Ag) can
also be used as the plasmonic layer to attain sharper SPR spectra
with higher sensitivity, and other protective coatings such as
Titanium dioxide (TiO.sub.2) can be used depending on requirements.
Note that adding a protection layer realized from a dielectric
material like ZrO.sub.2 may result in guided-wave SPR or
coupled-wave SPR, particularly if the protection layer is thick
enough (i.e., approximately a few hundreds of nanometers in the
visible) to support guided modes. In the embodiment above, the
protective layer is much thinner (i.e., approximately a few tens of
nanometers) than the cutoff thickness required to support the
higher order guided modes. However, with thin layers of high
refractive index material there is partial wave guiding that can
occur. In these situations, the wave guide material can be thin
enough such that a large fraction of the evanescent wave will be
exposed to the analyte, thereby enhancing SPR sensitivity. The
light beam reflected at the interface of the substrate 111 and the
thin-film stack 113, which has intensity loss due to SPR at each
wavelength, passes through the prism 109 and is directed to a
polarizer 115 (for example, the CM1-PBS252 polarizer commercially
available from Thorlabs, USA). The polarizer 115 separates this
reflected light beam into a p-polarized beam and an s-polarized
beam, which are each collimated by respective collimators 117A,
117B into separate light guides 119A, 119B (e.g., fiber patch
cables) for supply to corresponding spectrometers 121A, 121B (for
example, UV-VIS spectrometers, HR2000+CG-UV-NIR, with a usable
wavelength range 200-1100 nm commercially available from Ocean
Optics, USA). The spectrometer 121A measures the spectra of the
p-polarized beam (which represents the intensity of the p-polarized
beam over a number of different wavelengths), while the
spectrometer 121B measures the spectra of the s-polarized beam
(which represents the intensity of the s-polarized beam over a
number of different wavelengths).
A programmed computing system 123 (such as a PC or workstation)
acquires the spectra of the p-polarized beam from the spectrometer
121A and the spectra of the s-polarized beam from the spectrometer
121B. It also performs data storage and analysis of the p-polarized
beam spectra and the s-polarized beam spectra to determine an SPR
peak wavelength. In embodiment(s), the SPR peak wavelength can be
extracted from the p-polarized beam spectra and the s-polarized
beam spectra in two steps. First, an absorbance spectrum can be
calculated by dividing a characteristic spectrum of the p-polarized
beam (which can be determined by averaging the p-polarized beam
spectra per wavelength as measured by the spectrometer 121A over a
given measurement time interval) by a characteristic spectrum of
the s-polarized beam (which can be determined by averaging the
s-polarized beam spectra per wavelength as measured by the
spectrometer 121B over the same measurement time interval). Note
that s-polarized light does not couple to surface plasmons.
Therefore, the s-polarized beam that is measured by the
spectrometer 121B does not experience SPR losses and provides a
reference spectrum. Second, a peak detection algorithm is used to
determine the SPR peak wavelength from the absorbance spectrum. The
SPR peak wavelength can be plotted versus time to observe the
evolution of the SPR peak wavelengths during one or titration
experiments as described herein. Furthermore, a calibrated model
can be used to convert the SPR peak wavelength(s) into an effective
refractive index for interpretation. An exemplary calibrated model
is described herein.
The SPR sensor 101 includes a flow cell 125 with a chamber disposed
adjacent the thin-film stack 113 (e.g., adjacent the protection
layer of the thin-film stack 113). In embodiments, the flow cell
125 can be formed from an aluminum block with a well-defined total
internal dead-volume (for example, 42.5 .mu.L). Fluid flows through
the chamber of the flow cell 125, which includes an SPR sensing
zone in the vicinity where the light beam is reflected at the
interface of the substrate 111 and the thin-film stack 113 as shown
in FIG. 1. Note that the SPR sensing zone is located on top of the
fluid flow through the chamber of the flow cell 125 to ensure
gravitational settling was not the primary mechanism for detecting
asphaltene deposition as described herein.
A sample of crude oil (e.g., reservoir fluid) is loaded into a
syringe pump 127A. N-heptane (e.g., the titrant and a precipitant
of asphaltenes) is loaded into a syringe pump 127B. The crude oil
output of the syringe pump 127A and the n-heptane output of the
syringe pump 127B is supplied a Y-connector 129 to form a mixture
of the two fluid components, which is directed to the flow cell 125
by tubing 131. A check valve (not shown) can be fluidly coupled
between the syringe pump 127B and the Y-connector 131 to prevent
backflow, if desired. Waste from the flow cell 125 is directed by
tubing 133 to a waste container (not shown). The computing system
123 can interface to the syringe pumps 127A, 127B to provide
automatic control over the flow rate of the crude oil output of the
syringe pump 127A as supplied to the Y-connector 129 and the flow
rate of the n-heptane output of the syringe pump 127B as supplied
the Y-connector 129. In this manner, the computing system 123 can
provide automatic control the relative concentrations of the crude
oil and the n-heptane in the mixture supplied to the flow cell 125
for the titration experiments as described herein.
In embodiment(s), the SPR sensor 101 is designed for a range of
refractive indices that spans 1.4-1.7, as is expected for crude
oil. The dynamic range of measurable refractive indices can be
tailored by changing the metallic and protective layer materials
and thicknesses of the thin-film stack 113.
The SPR sensor 101 as described above can be configured to carry
out one or more titration experiments. The SPR sensing zone of the
flow cell 125 can be filled with toluene between titration
experiments. The titration experiment begins by the computer system
123 controlling the syringe pumps 127A, 127B to inject a mixture of
the crude oil and n-heptane into the flow cell 125, which displaces
the toluene stored in the tubing and flow cell 125. This can be
accomplished by a ramp infusion of both the crude oil and
n-heptane. In embodiments, the crude oil can be initially injected
at 480 L/min and the n-heptane at 20 L/min. The combined flow rate
was maintained at 500 .mu.L/min yielding a residence time of 21.5
seconds from Y-connector 129 to the flow cell output. Over the
course of one hour, the crude oil flow rate can be linearly ramped
down to 240 .mu.L/min and the n-heptane flow rate can be linearly
ramped up to 260 .mu.L/min. This provided a continuous
n-heptane:oil volume ratio that spans from 0.04 to 1.08. At regular
intervals (e.g., every one second) during the titration experiment
as the n-heptane:oil volume ratio is continuously varied over this
range, the computing system 123 determines the SPR peak wavelength
from the spectra of the p-polarized beam and the spectra of the
s-polarized beam as measured by the spectrometers 121A, 121B as
described above. After the titration experiment, the system can be
flushed with toluene and stored until the next experiment.
In embodiment(s), the mixing of the crude oil and n-heptane streams
can be accomplished in the laminar flow regime, meaning that the
mixing is governed largely by diffusion across the cross-sectional
area of the tubing 131. After the Y connector 129 (i.e., mixing
junction), there are two side-by-side streams, one of n-heptane and
one of crude oil. Since n-heptane is the smaller and faster
diffusing molecule, it will set the characteristic time for mixing.
The length of the tubing 131 can be configured to allow for the
desired diffusion of the n-heptane within the cross-sectional
diameter of the tubing 131. Also, the kinetics near the onset of
asphaltene deposition are particularly slow, often requiring hours
or days to form micron sized asphaltene aggregates. The ability of
SPR sensor 101 to detect nanometer-sized asphaltene depositions
circumvents the need to wait for asphaltene aggregates to reach a
microscopically detectable size (.about.1 .mu.m).
The methodology of the titration experiment is shown in FIG. 2A. In
embodiment(s), all measurements can be performed at room
temperature between 21-24.degree. C. and 1 atmosphere of pressure.
Initially, the crude oil alone (without any n-heptane) is flowed
through the flow cell 125, and the computing system 123 determines
the SPR peak wavelength that is characteristic of the crude oil,
which is labeled as point "1" in the graph on the right side of
FIG. 2A. The SPR peak wavelength depends on the refractive index of
the crude oil, where high density oils typically have higher
refractive indices and thus longer SPR peak wavelengths. As
n-heptane is added, the computing system 123 determines the SPR
peak wavelength, which will blue-shift toward shorter
wavelengths--labeled as point "2" in the graph on the right side of
FIG. 2A. This is because the SPR sensor 101 is detecting the
diluted crude oil, which has a lower refractive index-tending
toward n-heptane. However, at a certain point, the amount of added
n-heptane will induce asphaltene precipitation that may lead to
deposition. Although the diluted crude oil fluid has a lower
refractive index at higher titration ratios, the asphaltenes are
denser and have a higher refractive index. If a deposit of
asphaltenes forms in the SPR sensing zone, the computing system 123
will determine an SPR peak wavelength that starts to red-shift to
longer wavelengths--labeled as point "3" in the graph on the right
side of FIG. 2A. The amount of n-heptane is further increased in
relation to the crude oil, leading to the precipitation and
deposition of the otherwise more soluble asphaltenes. This
continues until the deposit formed is thick enough to completely
fill the SPR sensing zone and a plateau is reached--labeled as
point "4" in the graph on the right side of FIG. 2A. Here the SPR
sensor 101 becomes blind to any further deposition of asphaltenes,
but the final plateau wavelength provides an indication on the
density of the asphaltene deposit within the SPR sensing zone.
Exemplary operations of the titration experiment of FIG. 2A is
shown in FIG. 2B, which begins in block 201 where the computer
processing system 123 controls the syringe pumps 127A, 127B to flow
the crude oil sample alone thru the chamber of the flow cell
125.
In block 203, the computer processing system 123 records and stores
the p-polarized spectral data output by the spectrometer 121A as
well as the s-polarized spectral data output by the spectrometer
121B as the crude oil sample alone flows thru the chamber of the
flow cell 125.
In block 205, the computer processing system 123 waits for
expiration of a residence time limit and then proceeds to block
207.
In block 207, the computer processing system 123 is configured to
adjust the injection rate of the syringe pumps 127A, 127B to flow a
mixture of crude oil sample and n-heptane thru the chamber of the
flow cell (where the relative concentration of the n-heptane in the
mixture increases over successive iterations of block 207).
In block 209, the computer processing system 123 determines if the
last iteration of the injection rate adjustment has been performed.
If not, the operations returns to block 203 to record and store the
p-polarized spectral data output by the spectrometer 121A as well
as the s-polarized spectral data output by the spectrometer 121B as
the mixture of the crude oil sample and n-heptane flows thru the
chamber of the flow cell 125, and block 205 to wait for expiration
of a residence time limit and then proceed to block 207 for
adjusting the relative concentration of the n-heptane in the
mixture for the next iteration. If yes, the operations continue to
block 211.
In block 211, the computer processing system 123 can be configured
to evaluate the stored optical spectral data to determine SPR peak
wavelengths over time, and evaluate conditions for onset of
asphaltene deposition based on the SPR peak wavelengths over
time.
In block 213, the computer processing system 123 can be configured
to use a model to relate the SPR peak wavelength measured by the
SPR sensor in block 211 to an effective refractive index as well as
density of the asphaltene components of the crude oil sample.
In other embodiment(s), the titration experiments as described
herein can substitute the n-heptane with another precipitant of
asphaltenes, such as n-hexane, n-pentane, petroleum ether, ethyl
acetate, alcohols and any other fluid that precipitates
asphaltenes.
In embodiment(s), a model of the SPR sensor 101 can be used to
relate the SPR peak wavelength measured by the SPR sensor 101 to a
refractive index of the crude oil. In one embodiment, the model
employs a matrix formalization that account for the multi-layered
system, including the prism, index matching fluid, substrate,
thin-film stack layers (Ti/Au/ZrO2), and sensed fluid/deposit
layer. For the SPR sensor 101, the s-polarized and p-polarized
reflected light intensity at each wavelength can be calculated
as:
.times..times..times..times..times..times..function. ##EQU00001##
where R is the reflectance, I.sub.in and I.sub.out are the input
incident light intensity and the output reflected light intensity
of the beam propagating inside the prism 109, respectively; r is
the reflection coefficient, and M is the matrix representation of
the substrate 111 and thin-film stack 113 that links the incident,
reflected and transmitted electric field amplitudes
(E.sub.i,E.sub.r,E.sub.t). The superscripts s or p signify either
s- or p-polarized light. The matrix representation of the
multi-layered system can be calculated as:
.function..times..times..times..times..times..times..times..times..times.-
.theta..times..times..times..times..theta..times..times..times..times..tim-
es..times..theta..times..times..theta..times..times..times..times..times..-
times..times..times..times..times..times..times..times..times..theta.
##EQU00002## where N is the number of layers (1=0, 1, 2, . . . , s)
in the multi-layered system, D.sub.l is the dynamical matrix for
the respective layer l of the multi-layered system, and P.sub.l is
the associated propagation matrix for the respective layer l of the
multi-layered system. For each respective layer l of the
multi-layered system, n.sub.l is the complex index of refraction,
.theta..sub.l is the complex angle of propagation, k.sub.l is the
component of the wave vector along the direction of propagation,
d.sub.l is the thickness of the layer, and w is the angular
frequency of light. The incident medium is l=0 and the sample
medium is l=s; where, the layer stack order is substrate
(sapphire)-adhesion layer (titanium)-plasmonic layer
(gold)-protection layer (zirconium dioxide)-hydrocarbon. For the
multi-layered stack, the layer thicknesses are known for sapphire,
titanium, gold, and zirconium dioxide. Also, the refractive indices
for the sapphire, titanium, gold, and zirconium dioxide layers are
readily available from the literature or they can be measured for
each sensor for improved accuracy. The wavelengths, angular
frequencies, and the complex angles of propagation are known. The
reflected light intensities by wavelength are also known, as
measured by the spectrometer. Thus, from the model, the remaining
unknowns are the "effective complex refractive index" of the sample
at each wavelength and the depth or thickness of the sensed layer.
It is assumed that the sample is homogenous and that it completely
fills the SPR penetration depth with a sufficiently large
thickness. Therefore, the effective refractive index of the sample
can be determined by numerical iteration.
The use of a complex angle of propagation is required to
accommodate the evanescent waves. Complex refractive indices as
functions of wavelength from the literature were also used for the
various materials. As the index of refraction used in these
equations is represented by a complex number, it mathematically
incorporates both a) the attenuation losses via the imaginary part
and b) the phase velocity changes via the real part. Therefore,
equations 1-6 are generalized and account for both attenuation and
phase velocity changes. In the case of heptane-toluene solutions
used for calibration, the assumption is that the absorption from
500-800 nm is negligible and thus the imaginary part is
insignificant and the Lorentz-Lorenz equation is used to determine
the effective refractive indices for various mixtures. However, in
the case of crude oil, there may be a minor degree of attenuation
at these wavelengths and this will be addressed in future sections.
Software code (such as Matlab code) can be written to implement the
above model and perform the calculations over a range of
wavelengths (400 nm-900 nm) and incident angles
(76-77.degree.).
The model of the SPR sensor 101 can be calibrated or tuned using
mixtures of n-heptane (a precipitant of asphaltenes) and toluene (a
solvent that dissolves asphaltenes). The syringe pump 127A is
loaded with toluene and the syringe pump 127B is loaded with
n-heptane. Initially, the syringe pumps 127A, 127B can be
configured to flow toluene alone through the flow cell 125 at a
desired flow rate (for example, at 1 mL/min for 5 minutes). Next,
the syringe pumps 127A, 127B are configured to flow toluene and
n-heptane through the flow cell 125 at flow rates (e.g., toluene at
0.0.9 mL/min and n-heptane at 0.1 mL/min for 4 minutes) yielding an
n-heptane:toluene volume fraction of 0.1. The volume fraction was
then successively incremented by steps of 0.1 (preferably for 4
minutes at each step). Finally, the syringe pumps 127A, 127B can be
configured to flow n-heptane alone through the flow cell 125 at a
desired flow rate (for example, at 1 mL/min for 5 minutes),
followed by a flush with toluene. The spectra of s-polarized light
and the p-polarized light can be collected by the spectrometers
121A, 121B continuously during this process. The s-polarized light
undergoes total internal reflection and does not lose intensity due
to excitation of surface plasmons, providing simultaneous
correction of baseline shifts in light intensity. The computer
system 123 can determine the SPR peak wavelength of the absorbance
spectrum versus the variable n-heptane:toluene volume fractions of
the calibration process. The computer system 123 can also be
configured to use the model of the SPR sensor 121 as described
above to determine the SPR peak wavelength for different
n-heptane:toluene volume fractions used in the calibration process.
The computer system 123 can adjust or tune certain parameters of
the model (such as the refractive index of the zirconium dioxide
layer of the thin-film stack) such that the SPR peak wavelengths
produced by the model matches the measured SPR peak wavelengths
determined by the computer system 123 at different
n-heptane:toluene volume fractions used in the calibration process.
Note that the calibrated or tuned model can be used to determine
the effective refractive index of the crude oil from the SPR peak
wavelength measured by the SPR sensor 101. In other embodiments,
the model of the SPR sensor 101 can be calibrated or tuned using
mixtures where the n-heptane is substituted by some other
precipitant of asphaltenes (such as n-hexane, n-pentane, petroleum
ether, ethyl acetate, alcohols and any other fluid that
precipitates asphaltenes), and the toluene is substituted by some
other solvent that dissolves asphaltenes (such as dichloromethane
(DCM), xylenes, benzene, methyl naphthalene, cyclohexane,
tetrahydrofuran (THF), chloroform, trichloroethylene,
tetrachloroethylene, carbon tetrachloride, and any other fluid that
dissolves asphaltenes).
The effective refractive index of the crude oil can be related to
density of the crude oil based on a correlation determined from the
results of crude oils with known densities. In one example,
correlation has been used to relate the refractive index (RI) of
the crude oil can to density (.rho.) of the crude oil (in
grams/cm.sup.3) as follows: .rho.=(3.0983RI)3.7978. (7)
To assess the suitability of the SPR sensor 101 in measuring
asphaltene deposition onset, a stepwise titration experiment of a
representative crude oil was performed while the optical spectra
and SPR peak wavelength were recorded. The representative crude oil
had a density of 0.8844 g/cm.sup.3 and an API of 28.5. The
representative crude oil had the following compositional components
by weight percentage, 54.4% saturates, 21.9% aromatics, 18.8%
resins, and 4.3% asphaltenes. FIGS. 3A and 3B shows the SPR data
acquired from the stepwise titration experiment of the
representative crude oil with n-heptane. FIG. 3A shows the light
intensity spectra for a selected number of n-heptane:oil volume
ratios, and FIG. 3B shows the SPR peak wavelength versus time as
the n-heptane:oil volume ratio was varied over time. The SPR peak
wavelength is well defined at 651 nm for a volume ratio of 0.05,
approximately that of the neat crude oil-650 nm. As more n-heptane
is added, the SPR peak wavelength shifts downward to 648 nm at a
volume ratio of 0.11 and further to 644 nm at a volume ratio of
0.18. The dilution of crude oil with n-heptane produces
blue-shifting SPR peaks (FIG. 3A) and the expected decline in SPR
peak wavelength (FIG. 3B). When the volume ratio is 0.25,
asphaltene deposition has occurred and localized surface
depositions are initiated-likely the source of the noisy SPR peak
wavelength signal. As the volume ratio increases to 0.33, the
deposition rate increases and is marked by the abrupt rise in the
SPR peak wavelength. At higher volume ratio of 0.43, the deposition
rate increases with a steeper slope and continues until reaching
the maximum penetration depth of the SPR sensing zone. The final
SPR peak wavelength (i.e., refractive index) of the surface deposit
is higher than that of the initial crude oil, indicating the heavy
crude oil components (i.e., asphaltenes) are concentrated and
adsorbed on the sensor surface. Diluted crude oil may also be
trapped within the asphaltene deposit layer. The formation of the
deposit layer can be observed by the broadening and red-shifting
SPR peak wavelengths (FIG. 4A) and the rising SPR peak wavelength
(FIG. 4B). The sensing surface was purposefully placed on top of
the fluid flow, and the results indicate that the primary mechanism
of deposition was not gravitation settling of the asphaltene
particles.
For the representative crude oil, the asphaletene deposit has an
SPR peak wavelength of approximately 680 nm corresponding to an
effective refractive index of 1.539, or 0.028 refractive index
units higher than the native crude oil. Using the density
correlation of Eqn. 7, the estimated density of the deposit is
0.970 g/cm.sup.3, compared to the initial crude oil density of
0.884 g/cm.sup.3, indicating that deposit consists of the heavier
components within the crude oil.
To further assess the performance of the SPR sensor 101 in
measuring asphaltene deposition onset, ramped titration experiments
of three representative crude oils was performed while the optical
spectra and SPR peak wavelength were recorded. A ramped titration
provides a more continuous sweep of n-heptane:crude oil volume
ratio, allowing finer resolution in measuring the onset of
asphaltene deposition. The three representative crude oils are
referred to as crude oil 1, crude oil 2 and crude oil 3. Crude oil
1 had a density of 0.8844 g/cm.sup.3 and an API of 28.5. Crude oil
1 had the following compositional components by weight percentage,
54.4% saturates, 21.9% aromatics, 18.8% resins, and 4.3%
asphaltenes. Crude oil 2 had a density of 0.8574 g/cm.sup.3 and an
API of 33.5. Crude oil 2 had the following compositional components
by weight percentage, 59.1% saturates, 23.0% aromatics, 15.7%
resins, and 1.6% asphaltenes. Crude oil 3 had a density of 0.9275
g/cm.sup.3 and an API of 40.2. Crude oil 3 had the following
compositional components by weight percentage, 40.2% saturates,
27.1% aromatics, 23.9% resins, and 8.5% asphaltenes.
FIGS. 4A and 4B shows the results from three ramped titration
experiments, showing the SPR peak wavelength measured versus time
as the n-heptane:oil volume ratios was varied over time, and also
versus the n-heptane:oil volume ratio. FIGS. 4A and 4B highlight
the ability of the SPR sensor to measure the variation in:
asphaltene deposition onset, the rate of deposition, and the
density of the final deposit formed. The asphaltene deposition
onset volume ratios were 0.202 for crude oil 1, 0.311 for crude oil
2, and 0.390 for crude oil 3. Crude oils 1 and 3 had higher
asphaltene contents than crude oil 2, but they deposited more
slowly than crude oil 2 after asphaltene deposition. The deposits'
density were inversely proportional to the initial crude oil
density, which can be determined from the SPR peak wavelength at
steady-state and Eqn. 7. The lightest crude oil, crude oil 2 (with
a density of 0.857 g/cm.sup.3), had a final SPR peak wavelength of
690 nm with an effective refractive index of 1.547, yielding the
highest deposit density at 0.995 g/cm.sup.3. The heaviest crude
oil, crude oil 3 (with a density of 0.928 g/cm.sup.3), had a final
SPR peak wavelength of 667 nm with an effective refractive index of
1.528 and the least dense deposit at 0.935 g/cm.sup.3. The black
crude oil, crude oil 1 (with a density of 0.884 g/cm.sup.3) was in
the middle with a deposit density near 0.970 g/cm.sup.3. Since
asphaltenes are reported to have densities ranging from 1.1-1.2
g/cm.sup.3, it is likely that the deposit was an arrangement of
spotted islands or that the layer had entrapped fluid during
formation. Both would yield a lower effective deposit density. The
inverse relationship between neat crude oil density and deposit
density may be the result of a deposition mechanism and/or varying
asphaltene compositions.
The SPR sensor 101 provides a powerful tool for understanding the
mechanisms of asphaltene deposition. The SPR spectral data can be
informative by permitting observation of the time-wise formation of
the deposit. FIG. 5 shows the measured SPR absorbance spectra
spanning different titration ratios for crude oil 2. Below, we
provide one possible explanation for the evolution of the SPR
spectral data from our titration experiments.
In stage 1, the mixture of crude oil 2 and n-heptane is the primary
analyte responsible for the SPR peak wavelength in the sensing
region. The top-left panel of FIG. 5 shows an n-heptane:oil ratio
of r=0.05-0.08 with a resulting SPR peak wavelength of
approximately 645 nm. As the crude oil is further diluted with
n-heptane, e.g. ratio of r=0.16-0.20 in the top-right panel, the
SPR peak wavelength blue-shifts as expected to approximately 632
nm.
In stage 2, the gradual appearance of a second SPR peak indicates
that an initial deposit has formed. The SPR peak wavelength
continues to blue-shift to approximately 625 nm until the onset
point is reached at r=0.311, at which point the presence of another
peak is evident (r=0.29-0.35). This represents the beginning of
stage 2, where asphaltenes have started to form spots or islands on
the thin-film surface. However, the original SPR peak associated
with the fluid mixture continues to blue-shift slightly, down to
approximately 620 nm, as the titration ratio is increased. This
indicates that in stage 2, both the flowing mixture and the
asphaltene deposit are detected in the sensing region.
In stage 3, the asphaltene deposit occupies the majority of the SPR
sensing zone. As more asphaltenes deposit on the SPR sensing
surface, the deposit's SPR peak grows in amplitude and red-shifts
slightly from approximately 684 nm to approximately 691 nm.
Conversely, the fluid's SPR peak shrinks and eventually stabilizes
without shifting in wavelength. In this stage, the two SPR peaks
are present at all times, but the fluid peak is largely static
because the fluid is trapped within porous regions of the
asphaltene deposit, after r=0.47-0.53.
Finally, in stage 4, the entire SPR sensing zone is occupied with a
static hybrid deposit. After r=0.61-0.69, neither the fluid nor the
asphaltene deposit SPR peaks have notable shifts in wavelength or
changes in amplitude. The proposed 4-stage mechanism explains the
evolution of the SPR peak wavelengths under varying titration
ratios.
FIG. 6 summarizes the 4-stages by plotting the SPR peak locations
of both the fluid and the deposit for the crude oil 2 data. A
Levenberg-Marquadt non-linear least-square fitting approach based
on two peaks was performed, where both peaks were modelled with a
pseudo-Voigt profile--a linear combination of Gaussian and
Lorentzian line profile functions. The momentary rise in stage two
is an artefact from fitting, where the spectral data showed a
single large-flat-peak in the crossover region from fluid to
deposit--as observed in FIG. 5 around a ratio of 0.40. The dynamic
SPR sensor data, like that of FIGS. 5 and 6, can inform deposition
models by enabling simultaneous observation of both crude oil fluid
and the deposit layer during such deposition events.
The experiments described herein show that the operation of the SPR
sensor is robust in measuring asphaltene depositions when exposed
to unprocessed crude oil samples that were titrated with a
precipitant. More specifically, the operations of the SPR sensor
can directly quantifies asphaltene deposition onset. Shifts in the
SPR peak wavelength can be used to determine the onset and
deposition of asphaltenes from titration experiments. A model of
the SPR sensor can be tuned or calibrated and used to relate SPR
peak wavelength to an effective refractive index of the crude oil,
which can be then related to an estimate of deposit density. The
ability to simultaneously measure both the fluid's refractive
index/density and the solid deposit's refractive index/density, can
enable real-time measurement of asphaltene/organic deposition under
live conditions. Therefore, the SPR sensor can enable direct
feedback for flow assurance workflows, monitoring stability for
operations like solvent dilution, sample depressurization.
The SPR sensor 101 can also be used to quantify the phase behavior
of hydrocarbon fluids based on a step change in the SPR peak
wavelength, which can include one or more of the following
applications: Detection of bubble point; the formation of vapor
(may be also dissolution) from a hydrocarbon fluid induced by
temperature and pressure changes. The SPR sensor can be used to
detect either the vapor or liquid phases. Detection of liquid
condensation; the formation of a liquid film on the sensor surface
from hydrocarbon vapors induced by temperature or pressure changes.
Detection of hydrate formation induced by temperature or pressure
changes. Detection of scaling or inorganic precipitation induced by
composition, temperature or pressure changes. Detection of
asphaltene onset; the formation of asphaltenes aggregates in the
hydrocarbon fluid induced by temperature, pressure or composition
changes. The SPR sensor can be used to detect either the liquid
phase (maltenes) or a precipitated/deposited solid phase
(asphaltenes). Sample fluid typing by means of measuring the
direction and/or magnitude of the SPR shift when undergoing phase
change. In another aspect, a compact and robust SPR probe sensor is
provided that can be used to quantify the phase behavior of
hydrocarbon fluids in ruggedized applications, such as part of a
downhole tool that experiences high pressure high temperature
conditions of a downhole wellbore environment or as part of a
surface-located system at a wellsite or pipeline. Similar to the
SPR sensor of FIG. 1, the SPR probe sensor is based on a
surface-sensitive optical phenomenon known as surface plasmon
resonance, or SPR. Surface plasmon resonance describes a condition
in which light incident onto a highly conductive metallic film
couples into resonant charge oscillations of the metal, resulting
in light that is effectively "glued" to the surface of the film. In
this trapped state, light is highly sensitive to slight
perturbations in the dielectric environment in the immediate
vicinity of the film (less than 1 .mu.m away). This property is
useful for quantifying the phase behavior of hydrocarbon fluids
based on a step change in the SPR peak wavelength, which can
include one or more of the following applications: Detection of
bubble point; the formation of vapor (may be also dissolution) from
a hydrocarbon fluid induced by temperature and pressure changes.
The SPR sensor probe can be used to detect either the vapor or
liquid phases. Detection of liquid condensation; the formation of a
liquid film on the sensor surface from hydrocarbon vapors induced
by temperature or pressure changes. Detection of hydrate formation
induced by temperature or pressure changes. Detection of scaling or
inorganic precipitation induced by composition, temperature or
pressure changes. Detection of asphaltene onset; the formation of
asphaltenes aggregates in the hydrocarbon fluid induced by
temperature, pressure or composition changes. The SPR sensor probe
can be used to detect either the liquid phase (maltenes) or a
precipitated/deposited solid phase (asphaltenes). Sample fluid
typing by means of measuring the direction and/or magnitude of the
SPR shift when undergoing phase change. The SPR probe sensor
embodiments as described herein can be more amendable to the
downhole high-pressure high temperature environment than other
methods, as the optical components of the SPR probe sensor are
self-aligned, the system requires no motorized parts, and the
spectroscopic technique readily integrates with existing downhole
tools.
Note that a phase transition in a hydrocarbon reservoir fluid can
occur as the pressure and temperature of the fluid deviates from
reservoir conditions. Retrograde condensates are one type of
hydrocarbon fluid that exhibit a dewpoint (formation of a liquid
phase from a gas phase) during isothermal depressurization at the
temperature of interest. Presence of the liquid phase depends on
temperature and pressure conditions in the reservoir allowing
condensation of liquid from vapor. FIG. 15 shows the phase diagram
of a typical gas condensate. The fluid is in gaseous form at
pressures above the solid curve, while it forms liquid condensate
once the pressure drops below the solid curve. Point 1 in FIG. 15
represents the gaseous state of the system at a given temperature.
As the pressure drops at constant temperature, the system crosses
the dew point curve (solid curve) and liquid phase forms (phase
transition from gas-to-liquid). Point 2 in FIG. 15 depicts the
two-phase state of the system. Formation of liquid phase in the
pores during production of a gas field results in reduced liquid
recovery. Condensate dropout near the wellbore can significantly
reduce the productivity index of the well. In severe cases the well
can prematurely die decreasing overall recovery under naturally
flowing conditions. Therefore, it is imperative to measure the dew
point as well as liquid drop-out of such hydrocarbon fluids at
reservoir condition and plan the production accordingly.
Phase behavior studies of lean gas condensates are of growing
importance in reservoir fluid analysis. Saturation pressure (psat)
or the dew point of a gas condensate is an important
thermo-physical property of such fluids. However, measurement of
the dew point is usually difficult to perform in conventional
Pressure-Volume-Temperature (PVT) systems. The complications stem
from the difficulty in detecting and quantifying very small volumes
of liquid in the gas. The dew point measurement becomes
increasingly difficult as the liquid content of the gas reduces.
Dead volumes in conventional PVT cells limit the minimum measurable
liquid volumes. The minimum liquid volume fraction is a function of
cell geometry. Conventional methods using PVT cells run into major
difficulties when it comes to measuring the dew point of fluids
with small volume liquid content (e.g., lean condensate). There
have been attempts to increase the cell volume (e.g., 205 cc in
Sanchez Gas 250-1000 cell) to increase the amount of liquid
collected at and below dew point pressure. However, the increase in
accuracy comes at the cost of significantly larger sample volume
and operational difficulty. Furthermore, conventional techniques
suffer from poor repeatability, reproducibility, and accuracy.
Hence, there is a strong demand for a reliable, accurate and highly
sensitive technique for dew point and phase volume measurement.
In another example, the determination of asphaltene onset
conditions and also the amount of asphaltene precipitation under
varying conditions are essential measurements for both upstream and
downstream operations. It is useful to characterize asphaltene
behavior to optimize flow assurance and to prevent adverse
asphaltene drop out during production and processing of the oil.
Asphaltenes can deposit in reservoirs, wellbore tubing, flow-lines,
separators, etc. The deposits can interrupt and potentially stop
production due to the formation of plugs. The first step in the
deposition process is flocculation (aggregation) of molecules.
During production, the solubility of the asphaltenes in the crude
oil decreases as the pressure decreases as the fluid travels
through the reservoir and the well bore. The asphaltene onset
pressure (AOP) is the pressure at which asphaltenes first begin to
precipitate at a fixed temperature. Asphaltene deposition can begin
deep in the wellbore while the pressure is well above the bubble
point. Asphaltenes can also precipitate during miscible flooding
with CO.sub.2 and natural gases as well as due to comingling of
different fluids.
In accordance with some example embodiments, a method and apparatus
are provided for measuring hydrocarbon phase transitions, namely
dew point, bubble point and asphaltene onset pressure (AOP) at HPHT
conditions and downhole. The method utilizes surface plasmon
resonance to measure the refractive index shifts of reservoir
fluids when phase transitions are induced by pressure, temperature,
or composition changes.
Some example embodiments involve the design and experimental
workflow of an SPR probe sensor that can operate under high
pressure and high temperature conditions. In an example
implementation, the instrument includes two parts: the SPR sensor
probe and optionally a sample handling system for temperature and
pressure control/monitoring. The SPR sensor probe may be
constructed from an optical fiber (e.g., a sapphire optical fiber).
In some examples, one end of a fiber optic core can be coated with
a thin film of metal (e.g. gold, silver) and a thin film of
dielectric protection (e.g., zirconium oxide). The SPR sensor probe
can be excited using a polychromatic light source (e.g., a
broadband tungsten-halogen light source) providing light from
400-2400 nm, although other wavelengths may be suitable as per
application. The SPR coupling at the interface of the thin film of
metal is imprinted onto the spectra of the light reflected from the
SPR sensor probe or light transmitted by the SPR sensor probe,
which is measured by a spectrometer. The spectra of the reflected
or transmitted light as measured by the spectrometer can be
analyzed to determine an SPR peak wavelength. An abrupt change or
shift in the SPR peak wavelength can be used to detect phase change
of complex multi-component reservoir fluids in order to measure
bubble point, dew point, asphaltene onset or other relevant phase
transitions. The phase change can occur due to environmental
conditions or can be induced by the sample handling system.
FIGS. 7A to 7E illustrate example embodiments of a reflective-type
SPR sensor probe 710 where the SPR coupling at the interface of a
thin film of metal is imprinted onto the spectra of the light
reflected from the SPR sensor probe 710, which is measured by a
spectrometer 702. The SPR sensor probe 710 is part of a system 700
which includes four sub-components: a polychromatic light source
701, a four-port fiber splitter 705, a flow line 709 with the SPR
sensor probe 710 integral to the flow line 709, and a spectrometer
702. The polychromatic light source 701 can be a tungsten halogen
light supplying polychromatic radiation at wavelengths from
400-2400 nm, although other wavelengths or light source types may
be used as per application. The polychromatic light generated by
the light source 701 is directed into port 1 (labeled 703) of the
fiber splitter 705. The fiber splitter 705 transmits part of the
supplied polychromatic light to port 3 (labeled 707) of the fiber
splitter 705, where it is coupled to the fiber optic core of the
SPR sensor probe 710. The light that is supplied to the fiber optic
core of the SPR sensor probe 710 can undergo multiple total
internal reflections within the SPR sensor probe 710. Each
reflection may result in a loss of light intensity due to SPR
coupling where the light couples to or excites surface plasmon
oscillations at the interface of thin metal film and the
hydrocarbon fluid that flows through the flow line 709. The SPR
sensor probe 710 includes a mirror that reflects light backward
toward port 103 (labeled 707) of the fiber splitter 705. This
reflected light traverses the length of the SPR sensor probe 710
length once more, potentially losing additional light intensity due
to SPR coupling. Part of the reflected light (with losses due to
the SPR coupling) is transmitted by the fiber splitter 705 from
port 103 (labeled 707) to port 102 (labeled 704) of the fiber
splitter 705 for supply to the spectrometer 702. The spectrometer
702 measures the spectra of the reflected light (which represents
the intensity of the reflected light over a number of different
wavelengths). The fiber splitter 705 can also direct part of the
polychromatic light generated by the light source 701 via port 4
(labeled 706) to an optional spectrometer 708. The spectrometer 708
can measure the spectra of the polychromatic light (which
represents the intensity of the polychromatic light with over a
number of different wavelengths, with no losses due to SPR
coupling). This provides a reference spectrum and enables
correction for noise and long-term drift and also allows
normalization of the losses experienced due to the SPR coupling. In
accordance with some examples, the system 700 can be designed to
withstand downhole high-pressure high temperature environmental
conditions in a wellbore that traverses a subterranean
formation.
FIGS. 7B, 7C and 7D show three different configurations for the
flow line 709 of FIG. 7A. It should be understood that any suitable
flow line configuration and/or geometry may be provided and those
shown are illustrative examples. More specifically, the
configuration of the flow line 709 of FIGS. 7B and 7C employ flow
paths that are elbows, or 90-degree bends. In the configuration of
FIG. 7B, the SPR sensor probe 710 is disposed approximately along
the center of the flow path. In the configuration of FIG. 7C, the
SPR sensor probe 710 is disposed adjacent one of the walls of the
flow line 709. In both configurations, the part of the flow line
709 occupied by the SPR sensor probe 710 is analogous the flow cell
and associated SPR sensing zone of the SPR sensor of FIG. 1. In
both configurations, a buffer and seal 711 is provided which allow
the SPR sensor probe 710 to extend into the flow region of the flow
line 709 in a fluid-tight manner to prevent the sample fluid from
exiting the flow line 709 via the entrance point of the SPR sensor
probe 710. The flow region of the
FIG. 7D illustrates a configuration of the flow line 709 that
employs a straight flow path, and the SPR sensor probe 710 extends
transversely relative the flow path into the flow path of the flow
line. In this manner, the part of the flow line 709 occupied by the
SPR sensor probe 710 is analogous the flow cell and associated SPR
sensing zone of the SPR sensor of FIG. 1. In this configuration, a
buffer and seal 711 is provided which allow the SPR sensor probe
710 to extend into the flow region of flow line 709 in a
fluid-tight manner to prevent the sample fluid from exiting the
flow line 709 via the entrance point of the SPR sensor probe
710.
FIG. 7E shows an enlarged cross-sectional view of a sensing portion
of the SPR sensor probe 710 of FIG. 7A to 7D. This sensing portion
extends into the flow region of the flow line 709 such that it
interacts with the sample fluid flowing through the flow line 709.
The sensing portion includes a fiber optic core 751, which can be
realized from sapphire with a diameter of 250 .mu.m in this
example. An adhesion layer 753 of titanium or other suitable
material, which can have a thickness of 3 nm, can be used to bond
the fiber optic core 751 to metal layer 755 (in this example, a
layer of silver). The metal layer portion 755-1 adjacent the end of
the fiber optic core 751 is relatively thick (for example, on the
order or 300 nm) as compared to the metal layer portion 755-2 that
extends adjacent the lengthwise portion of the fiber optic core 751
(which has a thickness, for example, on the order or 40 nm). The
thick metal layer portion 755-1 forms a mirror adjacent the end of
the fiber optic core 751. A protective (dielectric) layer 757 of
zirconium oxide or other suitable dielectric material coats both
the thick metal layer portion 755-1 and the thin metal layer
portion 755-2.
Interaction of the sample fluid flowing through the flow line 709
on SPR coupling of light reflected by the metal layer portions
755-1 and/or 755-2 of the SPR sensor probe 710 can be used in
accordance with the SPR principles described herein to analyze the
sample fluid. More specifically, a programmed computing system
(similar to the computing system 123 of FIG. 1) can be configured
to acquire the spectra of the reflected light as measured by the
spectrometer 702 and the spectra of the polychromatic light as
measured by the spectrometer 708. It can also perform data storage
and analysis of such spectra to determine an SPR peak wavelength at
any given point in time as well as variations in SPR peak
wavelength over time. In embodiment(s), the SPR peak wavelength can
be extracted from the spectra of the reflected light as measured by
the spectrometer 702 and the spectra of the polychromatic light as
measured by the spectrometer 708 in two steps. First, an absorbance
spectrum can be calculated by dividing a characteristic spectrum of
the measured spectra (which can be determined by averaging the
p-measured spectra per wavelength as measured by the spectrometer
702 over a given measurement time interval) by a characteristic
spectrum of the polychromatic light as measured by the spectrometer
708 (which can be determined by averaging the spectra per
wavelength as measured by the spectrometer 708 over the same
measurement time interval). Note that polychromatic light measured
by the spectrometer 708 does not under SPR coupling that is
influenced by the sample fluid flowing through the flow line 709.
Therefore, the polychromatic light measured by the spectrometer 708
does not experience SPR losses and provides a reference spectrum.
Second, a peak detection algorithm is used to determine the SPR
peak wavelength from the absorbance spectrum. The SPR peak
wavelength can be plotted versus time to observe the evolution of
the SPR peak wavelengths to detect phase change of the sample fluid
flowing through the flow line 709. The phase change can occur due
to environmental conditions or can be induced by a sample handling
system. Such analysis can be used to measure bubble point, dew
point, asphaltene onset or other relevant phase transitions.
Furthermore, a calibrated model similar to the model used to
represent the SPR sensor of FIG. 1 can be used to convert the SPR
peak wavelength(s) into an effective refractive index for
interpretation.
FIGS. 8A to 8C illustrate example embodiments of a
transmissive-type SPR sensor probe 810 where the SPR coupling at
the interface of a thin film of metal is imprinted onto the spectra
of the light transmitted by the SPR sensor probe 810, which is
measured by a spectrometer 807. The SPR sensor probe 810 is part of
a system 800 which includes four sub-components: a polychromatic
light source 801, a four-port fiber splitter 805, a flow line 809
with the SPR sensor probe 810 integral to the flow line 809, and a
spectrometer 807. The polychromatic light source 801 can be a
tungsten halogen light supplying polychromatic radiation at
wavelengths from 400-2400 nm, although other wavelengths or light
source types may be used as per application. The polychromatic
light generated by the light source 801 is directed into port 1
(labeled 802) of the fiber splitter 803. The fiber splitter 803
transmits part of the supplied polychromatic light to port 2
(labeled 806) of the fiber splitter 803, where it is coupled to one
end of the fiber optic core of the SPR sensor probe 810. The light
that is supplied to the fiber optic core of the SPR sensor probe
810 can undergo multiple total internal reflections within the SPR
sensor probe 810. Each reflection may result in a loss of light
intensity due to SPR coupling where the light couples to or excites
surface plasmon oscillations at the interface of thin metal film
and the hydrocarbon fluid that flows through the flow line 809. The
opposite end of the fiber optic core of the SPR sensor probe 710
couples the resultant light (which reflects the loss of light
intensity due to SPR coupling) to the spectrometer 807. The
spectrometer 807 measures the spectra of the transmitted light
(which represents the intensity of the transmitted light over a
number of different wavelengths). The fiber splitter 803 can also
direct part of the polychromatic light generated by the light
source 801 via port 3 (labeled 804) to an optional spectrometer
805. The spectrometer 805 can measure the spectra of the
polychromatic light (which represents the intensity of the
polychromatic light with over a number of different wavelengths,
with no losses due to SPR coupling). This provides a reference
spectrum and enables correction for noise and long-term drift and
also allows normalization of the losses experienced due to the SPR
coupling. In accordance with some examples, the system 800 can be
designed to withstand downhole high-pressure high temperature
environmental conditions in a wellbore that traverses a
subterranean formation.
FIG. 8B illustrates a configuration of the flow line 809 that
employs a straight flow path, and the SPR sensor probe 810 extends
transversely relative the flow path into the flow path. It should
be understood that any suitable flow line configuration and/or
geometry may be provided and those shown are illustrative examples.
In the configuration of FIG. 8B, a buffer and seal 811a is provided
which allow the SPR sensor probe 810 to extend into the flow region
of flow line 809 in a fluid-tight manner to prevent the sample
fluid from exiting the flow line 809 via the entrance point of the
SPR sensor probe 810.
FIG. 8C shows an enlarged cross-sectional view of a sensing portion
of the SPR sensor probe 810 of FIGS. 8A and 8B. This sensing
portion extends into the flow region of the flow line 809 such that
it interacts with the sample fluid flowing through the flow line
809. The sensing portion includes a fiber optic core 851, which can
be realized from sapphire with a diameter of 250 .mu.m in this
example. An adhesion layer 852 of titanium or other suitable
material, which can have a thickness of 3 nm, can be used to bond
the fiber optic core 851 to a metal layer 853 that extends along
the lengthwise extent of the sensing portion. The metal layer 853
can be realized from silver with a thickness of 40 nm in this
example. A protective (dielectric) layer 854 of zirconium oxide or
other suitable dielectric material coats the metal layer 853 that
extends along the lengthwise extent of the sensing portion.
Interaction of the sample fluid flowing through the flow line 809
on SPR coupling of light transmitted by the SPR sensor probe 810
can be used in accordance with the SPR principles described herein
to analyze the sample fluid. More specifically, a programmed
computing system (similar to the computing system 123 of FIG. 1)
can be configured to acquire the spectra of the transmitted light
as measured by the spectrometer 807 and the spectra of the
polychromatic light as measured by the spectrometer 805. It can
also perform data storage and analysis of such spectra to determine
an SPR peak wavelength at any given point in time as well as
variations in SPR peak wavelength over time. In embodiment(s), the
SPR peak wavelength can be extracted from the spectra of the
transmitted light as measured by the spectrometer 807 and the
spectra of the polychromatic light as measured by the spectrometer
805 in two steps. First, an absorbance spectrum can be calculated
by dividing a characteristic spectrum of the measured spectra
(which can be determined by averaging the measured spectra per
wavelength as measured by the spectrometer 807 over a given
measurement time interval) by a characteristic spectrum of the
polychromatic light as measured by the spectrometer 805 (which can
be determined by averaging the spectra per wavelength as measured
by the spectrometer 805 over the same measurement time interval).
Note that polychromatic light measured by the spectrometer 805 does
not under SPR coupling that is influenced by the sample fluid
flowing through the flow line 809. Therefore, the polychromatic
light measured by the spectrometer 805 does not experience SPR
losses and provides a reference spectrum. Second, a peak detection
algorithm is used to determine the SPR peak wavelength from the
absorbance spectrum. The SPR peak wavelength can be plotted versus
time to observe the evolution of the SPR peak wavelengths to detect
phase change of the sample fluid flowing through the flow line 809.
The phase change can occur due to environmental conditions or can
be induced by a sample handling system. Such analysis can be used
to measure bubble point, dew point, asphaltene onset or other
relevant phase transitions. Furthermore, a calibrated model similar
to the model used to represent the SPR sensor of FIG. 1 can be used
to convert the SPR peak wavelength(s) into an effective refractive
index for interpretation.
Note that the fiber optic core 751 or 851 can be made of materials
other than those specified herein, as long as the material has a
higher refractive index than that of the fluid sample and supports
the spectrum of light propagation. Also note that the spectrometers
702, 708, 807, 805 (or other spectrometers described herein) can be
based on spectrally dispersive technologies or on discrete
photodiodes and filters.
In alternate embodiments, the SPR sensing system 700 or 800 as
described herein can be used to perform one or more titration
experiments to measure asphaltene deposition onset. The titration
experiment varies the volume ratio of n-heptane (or some other
asphaltene precipitant) relative to the crude oil of interest in
order to measure the onset of asphaltene deposition.
FIGS. 9 and 10 show exemplary sample handling elements that can be
utilized to measure phase transitions using the SPR sensing system
700 or 800 as described herein. The simplest configuration is that
shown in FIG. 9. Here, the sample reservoir is sub-sampled via a
pre-filtration unit into pressure controlled reservoir 1. The flow
cell of the respective SPR sensing system 700 or 800 as described
herein (labeled SPR detector in FIG. 9) bridges the pressure
controlled reservoir 1 and pressure controlled reservoir 2. All of
the fluid handling elements can be maintained at isothermal
conditions preset by the user. The isothermal conditions can be
maintained by closed loop control of a thermoelectric-based
heater/cooler apparatus (or other temperature control system) that
is thermally coupled to these fluid handling elements (including
the pressure controlled reservoir 1, flow cell and pressure
controlled reservoir 2) such that the fluid temperature of these
fluid handling elements is maintained at the isothermal conditions
preset by the user. Fluid(s) can be flowed through the flow line at
varying pressures by controlling the pressure differential between
reservoir 1 and reservoir 2, while simultaneously recording the SPR
spectra at each pressure condition. A phase transition will be
detected by an abrupt change in the SPR peak wavelength measured by
the SPR sensing system. Furthermore, the user can vary the
isothermal conditions of the fluid handling elements of the system
as desired.
FIG. 10 shows a more advanced sample handling elements that permits
filtration and removal of solids for the sample under
investigation. Filtration can remove solid particles like
asphaltenes that may foul the SPR probe surface over extended use.
Filtration would also permit more robust phase transition detection
by physically removing solid particles from the bulk sample fluid.
In another embodiment, an inline mixer can be added in the fluid
flow path between the pressure controlled reservoir 1 and the SPR
detector to ensure the sample is well-mixed. The use of an active
or passive mixer can enhance phase transition in the well-mixed
sample. Note that all of the fluid handling elements can be
maintained at predefined isothermal conditions. The isothermal
conditions can be maintained by closed loop control of a
thermoelectric-based heater/cooler apparatus (or other temperature
control system) that is thermally coupled to these elements such
that the fluid temperature of these elements is maintained at the
predefined isothermal conditions. Fluid(s) can be flowed through
the flow line at varying pressures by controlling the pressure
differential between reservoir 1 and reservoir 2, while
simultaneously recording the SPR spectra at each pressure
condition. A phase transition will be detected by an abrupt change
in the SPR peak wavelength measured by the SPR sensing system.
Furthermore, the isothermal conditions of the fluid handling
elements of the system can be varied as desired.
FIG. 11 is the workflow for determining phase transitions using the
SPR sensing system 700 or 800 as described herein. In block 1101,
the initial temperature is set at reservoir temperature (e.g.
150.degree. C.) and the flow line with SPR sensor probe (sample
chamber) is allowed to stabilize for a thermal equilibrium time, r,
before proceeding to sample loading. The thermal equilibrium time
is the time required for the flow line with SPR sensor probe to
reach the set temperature. Additional time may be added to the
thermal equilibration time to ensure thermodynamic steady-state of
the sample has been reached. In block 1103, the hydrocarbon fluid
sample (.about.1 mL) is then charged into the flow line with SPR
sensor probe at reservoir pressure (e.g., 15 kpsi) and the first
SPR spectrum is acquired.
The temperature-dependent and pressure-dependent phase transitions
of the hydrocarbon fluid in the flow line with SPR sensor probe can
then be characterized. The flow line with SPR sensor probe is
initially heated to a desired high temperature limit above the
phase transition temperature--typically the sample's reservoir
temperature. A pressure decrementing loop is then executed in
blocks 1105 to 1111. In this loop, consecutive SPR spectra are
acquired as the pressure of the flow line with SPR sensor probe is
gradually and incrementally lowered, until the low pressure limit
has been reached (below the phase transition). At each pressure
setpoint, the assembly is allowed to reach steady state prior to
acquiring the SPR spectra (block 1105), set by the equilibrium time
and monitored through the pressure and temperature sensors using
PID control loops with live feedback (thermocouples and pressure
transducers). This is required to ensure that the temperature and
pressure of the sample cell (and hydrocarbon fluid sample)
corresponds to the temperature and the pressure set by the user.
After a pressure loop is fully executed or a phase transition has
been detected, the pressure of the sample chamber is returned to
reservoir pressure in block 1113. In block 1115 and 1117, the
temperature of the sample chamber is decremented by a set amount,
and the pressure loop is executed again. The temperature parent
loop of blocks 1115 and 1117 (along with the children pressure
loops) is executed until a user specified lower temperature limit
is reached. The pressure loop and temperature loop can be executed
independently or in a nested manner as required by the type of
phase transition targeted.
The workflow of FIG. 11 can be implemented both in the laboratory
and downhole. FIG. 12 shows a laboratory system and FIG. 13 shows a
downhole tool implementation. The laboratory system of FIG. 12 has
three sample cylinders (labelled Cyl1, Cyl2, and Cyl3) to perform
sample handling. The cylinders were equipped with a floating
sealed-piston. The pressure in the cylinders can be controlled
using precision pumps (labelled pump1, pump2 and pump3, ISCO 65D,
Teledyne ISCO, Nebraska, USA). High pressure stainless steel tubing
and valves (High Pressure Equipment, Pennsylvania, USA) can be used
to control the flow of sample between the cylinders. Two high
pressure filters (10 .mu.m prefilter, High Pressure Equipment,
Pennsylvania, USA and VHP 0.2 .mu.m inline filter, IDEX Health
& Science, WA, USA) can be used in the setup. The flow line
with SPR sensor probe of the system 700 or 800 as described herein
(labeled "optical detection) is fluidly coupled between the inline
filter and Cyl3 to interrogate the sample at test conditions. The
SPR sensor probe can be excited with a halogen light source
(HL-2000, Ocean Optics, Florida, USA) and ultraviolet-visible-near
infrared spectrometer (HR2000+CG-UV-NIR, Ocean Optics, Florida,
USA) to acquire the spectrum of the oil. Two gauge pressure sensors
(Sensotreme GmbH, Ramsen, Switzerland, accuracy .+-.10 psi) can be
installed in the flow lines before and after the 0.2 .mu.m inline
filter to measure the pressures at the two locations (P1 at 1 and
P2 at 2). All the fluid handling components in the flow path can be
maintained at isothermal conditions corresponding to reservoir
temperature T.sub.res. Such isothermal conditions can be maintained
by closed loop control of a thermoelectric-based heater/cooler
apparatus (or other temperature control system) that is thermally
coupled to the fluid handling elements such that the fluid
temperature of these fluid handling elements is maintained at the
predefined isothermal conditions. The laboratory apparatus can be
manually controlled or completely automated.
FIG. 13 shows a downhole tool system 1300 with two SPR sensor
probes. Fluid is drawn into the downhole tool system 1300 for
analysis using the main tool flowline 1305. The tool system 1300
can be provided as part of a downhole tool in a drill string, a
downhole tool deployed by wireline, or some other downhole tool,
such as those described above. The system 1300 can be operated
according to the techniques described above to determine asphaltene
onset conditions and other phase transitions for formation fluids
received in the tool (e.g., by systematically depressurizing crude
oil drawn into the downhole tool, filtering aggregated asphaltenes,
and comparing measured optical SPR spectra). In the presently
depicted embodiment, crude oil is drawn into the measurement
apparatus from the main flowline 1305 through a membrane. The fluid
in the flowline may include water, and the membrane of at least
some embodiments is an oil-water separation membrane that inhibits
flow of water to other components of the measurement apparatus. A
valve controls flow of crude oil into a measurement section 1350.
Various sensors, along with a pressure sensor, can be provided
along the measurement section 1350 for characterizing the fluid.
These sensors should be placed downstream of the first SPR sensor
probe to avoid excess hold up volumes. The apparatus also includes
pistons 1 and 2, which can be used for mixing and depressurization
of the crude oil within the top measurement section. Pressure of
the crude oil within the measurement section be changed by moving
the piston 1 or 2 to change the volume of the crude oil. In some
embodiments, the apparatus is a microfluidic system, in which the
sensors are microfluidic sensors, the optical detection units
(e.g., SPR sensor probes, spectrometers) are miniaturized units,
and the pistons 1 and 2 are micropistons. The top portion of FIG.
13 (above the filter) implements the simplest SPR phase change
sensor platform shown in FIG. 9.
The measurement section 1350 can also implement the SPR phase
change sensor platform shown in FIG. 10. To accomplish the
filtration configuration, a valve above the filter can be opened to
allow the crude oil to flow through an asphaltene filter membrane.
The transmembrane pressure is regulated by pistons 1, 2 and 4 to
achieve suitable flow across the membrane. The filter collects
aggregated asphaltenes in the crude oil, such as those formed from
mixing and depressurization of the oil to a level below its AOP.
Any suitable filter could be used, and the filter may be identical
to the filter described above with respect to filtration unit. The
pressure of the crude oil in the measurement section, before and
after filtration, can be measured with two pressure sensors. The
SPR spectra of the crude oil can be determined by the two SPR
sensor probes upstream and downstream from the filter, but the tool
can also be operated with only the downstream SPR sensor probe. An
additional solvent filled reservoir and piston 3 can be used to
backflush the membrane and clean the tool via various valve
configurations. The same cleaning solvent can also be used as a
calibration reference for the SPR sensor probes, having a known
refractive index and the corresponding SPR peak wavelength. Two
waste ports are used to return fluids back to the main tool
flowline, prefilter--called asphaltenes waste, and
postfilter--called maltenes waste.
FIGS. 14A, 14C and 14E show the reflected or transmitted spectra
(labeled "collected light) and the reference spectra (labeled
"input light") as measured by the spectrometers of the SPR sensing
system 700 or 800 for a reservoir fluid sample that is experiencing
phase change. FIGS. 14B, 14D and 14F show the corresponding change
in SPR peak wavelength determined by the SPR sensing system 700 or
800 based on analysis of the reflected or transmitted spectra and
the reference spectra for the reservoir fluid sample that is
experiencing phase change.
Oilfield Systems
FIG. 16 depicts a rig 10 suitable for employing certain downhole
tool embodiments disclosed herein. In the depiction, rig 10 is
positioned over (or in the vicinity of) a subterranean oil or gas
formation (not shown). The rig may include, for example, a derrick
and a hoisting apparatus for lowering and raising various
components into and out of the wellbore 40. A downhole tool 51 is
deployed in the wellbore 40. The downhole tool 51 may be connected
to the surface, for example, via coiled tubing 50 which is in turn
coupled to a coiled tubing truck 55.
During operation, the downhole tool 51 may be lowered into the
wellbore 40. In a highly deviated borehole, the downhole tool 51
may alternatively or additionally be driven or drawn into the
borehole, for example, using a downhole tractor or other conveyance
means. The disclosed embodiments are not limited in this regard.
For example, the downhole tool 51 may also be conveyed into the
borehole 40 using drill pipe, a wireline cable or other conveyance
methodologies.
The example downhole tool 51 described herein may be used to obtain
and analyze samples of formation fluids in situ. For example, the
formation fluid samples can include natural gas, various gas
mixtures, oil or various oil mixtures. The downhole tool 51 can
include a probe assembly 52 for establishing fluid communication
between the downhole tool 51 and the subsurface formation. During
operation, the probe assembly 52 may be extended into contact with
the borehole wall 42 (e.g., through a mud cake layer). Formation
fluid samples may enter the downhole tool 51 through the probe
assembly 52 (e.g., via a pumping or via formation pressure). The
downhole tool 51 also includes an SPR sensor 1740 (FIG. 17) for
measuring at least one property relating to phase change of
formation fluid sample that enters the downhole tool 51 through the
probe assembly 52.
The probe assembly 52 may include a probe mounted in a frame (the
individual probe assembly components are not shown). The frame may
be configured to extend and retract radially outward and inward
with respect to the sampling tool body. Moreover, the probe may be
configured to extend and retract radially outward and inward with
respect to the frame. Such extension and retraction may be
initiated via an uphole or downhole controller. Extension of the
frame into contact with the borehole wall 42 may further support
the sampling tool in the borehole as well as position the probe
adjacent the borehole wall 42.
In some embodiments, such as those used in low permeability
formations, the probe assembly 52 may be replaced by packer
assembly (not shown). The disclosed embodiments are not limited in
this regard. As is known to those of ordinary skill in the art, a
packer assembly, when inflated, is intended to seal and/or isolate
a section of the borehole wall to provide a flow area with which to
induce fluid flow from the surrounding formation.
The downhole tool 51 can also include a downhole telemetry
subsystem (not shown) that communicates data signals and control
signals between the downhole tool 51 and a surface-located data
acquisition and control system, which can be part of the truck 55
or other surface-located system. The downhole telemetry subsystem
can employ a variety of telemetry methods, such as wired telemetry
methods that employ telemetry cables, drill pipe that incorporate
telemetry cables, or fiber optic cables, and wireless telemetry
methods, such as mud-pulse telemetry methods, electromagnetic
telemetry methods, and acoustic telemetry methods. The downhole
telemetry subsystem can also supply electrical power supply signals
generated by a surface-located power source for supply to the
downhole tool 51. The surface-located power source can be part of
the truck 55 or other surface-located system. The downhole tool 51
can also include a power supply transformer/regulator for
transforming the electric power supply signals supplied by the
surface-located power source to appropriate levels suitable for use
by the electrical components of the downhole tool 100. In alternate
embodiments, the downhole tool 51 can include a downhole power
source supply (such as a battery or turbine generator and/or energy
harvester for logging while drilling tools) that supplies
electrical power supply signals to the downhole tool 51.
While FIG. 16 depicts a particular downhole tool 51, it will be
understood that the disclosed embodiments are not so limited. For
example, downhole tool 51 may include a drilling tool such as a
measurement while drilling or logging while drilling tool
configured for deployment on a drill string. The disclosed
embodiments are not limited in these regards.
FIG. 17 shows the fluid flow circuit of the downhole tool 51 of
FIG. 16. The probe assembly 52 is depicted as being in contact with
borehole wall 42 for obtaining a formation fluid sample. In the
depicted embodiment, probe assembly 52 is in fluid communication
with a primary flow line 1710 including a fluid analysis module
1704 and a fluid pumping module 1720. The fluid pumping module 1720
is in fluid communication with the probe 52 and includes a pump
1722 and a bypass flow line 1724 with bypass valve 1725 that are
coupled in parallel with one another as depicted. The SPR sensor
1740 is in fluid communication with primary flow line 1710 and may
be configured to receive a formation fluid sample. The downhole
tool 51 can further include an isolation valve 1712 that is part of
the primary flow line 1710 as well as a discharge valve 1714 and a
fluid outlet line 1770 that are fluidly coupled to the primary flow
line 1710 as shown. The discharge valve 1714 and the fluid outlet
line 1770 can be configured for discharging unwanted formation
fluid into the annulus or into the subterranean formation. The
downhole tool 51 may further include one or more sample bottles
(not shown on FIG. 17) that are fluidly coupled to the primary flow
line 1710 by associated valves and have various functionality, such
as, for example, zero dead volume (flashing line), self-sealing
functionality, and/or being nitrogen-charged as is well known.
The probe assembly 52 may be engaged with the borehole wall 42 as
depicted so as to establish fluid communication between the
subterranean formation and the primary flow line 1710 (those of
ordinary skill will readily appreciate that the probe assembly may
penetrate a mud cake layer on the borehole wall so as to obtain
fluid directly from the formation). Examples of probes suitable for
use in the in the disclosed embodiments include the Single-Probe
Module or Dual-Probe Module included in the Schlumberger MDT.RTM.
or described in U.S. Pat. Nos. 4,860,581 and 6,058,773, which are
fully incorporated by reference herein. While not depicted it will
be understood that the probe assembly may include or more probes
coupled to a frame that may be extended and retracted relative to a
tool body. In the depicted embodiment, probe assembly 52 is an
inlet probe that provides a flow channel from the subterranean
formation to the primary flow line 1710. The downhole tool 51 may
further include one or more outlet probes (e.g., at the downstream
end of the fluid outlet line 1770) so as to provide a channel
through which fluid may flow from the primary flow line 1710 out of
the tool 51 and back into the formation. In such an embodiment,
fluid may be circulated from the formation into the primary flow
line 1710 and back into the formation.
Fluid analysis module 1704 may include substantially any suitable
fluid analysis sensors and/or instrumentation, for example,
including chemical sensors, optical fluid analyzers, optical
spectrometers, nuclear magnetic resonance devices, a conductivity
sensor, a temperature sensor, a pressure sensor. More generally,
fluid analysis module 1704 may include substantially any suitable
device that yields information relating to the composition of the
formation fluid such as the thermodynamic properties of the fluid,
conductivity, density, viscosity, surface tension, pressure,
temperature, and phase composition (e.g., liquid versus gas
composition or the gas content) of the fluid. While not depicted,
it will be understood that fluid analysis sensors may alternatively
and/or additionally be deployed on the downstream side of the fluid
pumping module, for example, to sense fluid property changes that
may be induced via pumping.
Fluid pumping module 1720 may include substantially any suitable
pump 1722. For example, the pump 1722 may include a reciprocating
piston pump, a retractable piston pump, or a hydraulic powered
pump.
The SPR sensor 1740 is fluidly coupled to the primary flow line
1710 by an intake valve 1738 and an exhaust valve 1739. The SPR
sensor 1740 can be embodied by any one of the SPR sensors described
herein (e.g., the SPR sensor of FIG. 1 or the SPR probe sensors of
FIGS. 7A and 8A) and configured to measure at least one property
relating to phase change of formation fluid sample obtained via the
probe 52 and the primary flow line 1610.
Referring to FIG. 18, an exemplary hydrocarbon production well 1810
is shown, which includes a wellbore casing 1814, which typically
includes a number of concentric casing strings (not shown). The
casing 1814 defines an annulus 1816 that extends downward from a
wellbore opening or entrance 1818 at the surface 1820. It is noted
that the surface 1820 may be either the surface of the earth, or,
in the case of a subsea well, the seabed. The casing 1814 extends
through a hydrocarbon production zone 1822 from which it is desired
to acquire production fluid. The casing 1814 has perforations 1824
disposed therethrough so that production fluid may enter the
annulus 1816 from the production zone 1822.
Production tubing 1828 is disposed downward within the annulus 1816
supported from a wellhead 1830 at the surface 1820. A production
tubing packer 1834 is set above the perforations 1824 to establish
a fluid seal between the production tubing 1828 and the casing
1814. The production tubing 1828 includes at least one fluid inlet
below the packer 1834 which permits fluid communication from the
annulus 1816 into the interior of the production tubing 1828 to
allow production fluid to flow to the wellhead 1830 (indicates as
arrows 1829) due to the formation pressure. In other embodiments,
artificial lift (such sucker-rod (beam) pumping, electrical
submersible pumping (ESP), gas lift and intermittent gas lift,
reciprocating and jet hydraulic pumping systems, plunger lift, and
progressive cavity pumps (PCP)), can be used to generate or assist
in flowing the production fluid through the interior of the
production tubing 1828 to the wellhead 1830.
The upper portion of the production tubing 1828 may optionally be
surrounded by liner or sleeve 1850 which extends from the well
opening 1818 downward within the annulus 1816. A packer 1852 can be
set at the lower end of the sleeve 1850 to establish a fluid seal
between the sleeve 1850 and the casing 1814. The sleeve 1850 can
provide additional isolation between the annulus 1816 and any fresh
water aquifers.
The wellhead 1830 can include an adjustable choke 1861 of a type
known in the art which is used to control the flow of production
fluids through the wellhead 1830. A lateral fluid flowline 1862
extends from the wellhead 1830 to the separator assembly 1863.
The separator assembly 1863 separates the gas/oil and water
components of the production fluids supplied thereto, which are
output by corresponding flowlines 1864, 1866 as shown. The
flowlines 1864 and 1866 carry the respective gas/oil and water
components of the production fluids to other surface-located
facilities (not shown). Such surface-located facilities can include
fluid collection systems (such as tanks), fluid processing devices
and/or pipelines.
An SPR sensor 1868 is fluidly coupled to the flow line 1864 by an
intake valve 1867 and an exhaust valve 1869. The SPR sensor 1864
can be configured to receive a sample of the gas/oil components of
the production fluids that is output by the separator 1863 and
carried by the flowline 1864. The SPR sensor 1840 can be embodied
by any one of the SPR sensors described herein (e.g., the SPR
sensor of FIG. 1 or the SPR probe sensors of FIGS. 7A and 8A) and
configured to measure at least one property relating to phase
change of production fluid sample obtained via the flowline
1864.
Computer Systems
Note that parts of the SPR sensors and systems as described above
can be implemented as computer program executed by a computer
processing platform (e.g., the computing system 123 of FIG. 1). The
computer program may be embodied in various forms, including a
source code form or a computer executable form. Source code may
include a series of computer program instructions in a variety of
programming languages (e.g., an object code, an assembly language,
or a high-level language such as C, C++, or JAVA). Such computer
instructions can be stored in a non-transitory computer readable
medium (e.g., memory) and executed by the computer processing
platform. The computer instructions may be distributed in any form
as a removable storage medium with accompanying printed or
electronic documentation (e.g., shrink wrapped software), preloaded
with a computer system (e.g., on system ROM or fixed disk), or
distributed from a server over a communication system (e.g., the
Internet or World Wide Web).
The computer processing platform may include a CPU, other
integrated circuitry (e.g., Application Specific Integrated
Circuits (ASIC)), programmable logic devices (e.g., a Field
Programmable Gate Arrays (FPGA) and/or discrete electronic
components coupled to a printed circuit board. Any of the methods
and processes described above can be implemented using such logic
devices.
FIG. 19 shows an example computing system 1900 that can be used to
implement the computer processing platforms of the SPR sensors as
described herein. The computing system 1900 can be an individual
computer system 1901A or an arrangement of distributed computer
systems. The computer system 1901A includes one or more analysis
modules 1903 (a program of computer-executable instructions and
associated data) that can be configured to perform various tasks
according to some embodiments, such as the tasks described herein.
To perform these various tasks, an analysis module 1903 executes on
one or more processors 1905, which is (or are) connected to one or
more storage media 1907. The processor(s) 1905 can be connected to
a network interface 1909 to allow the computer system 1901A to
communicate over a data network 1911 with one or more additional
computer systems and/or computing systems, such as 1901B, 1901C,
and/or 1901D. Note that computer systems 1901B, 1901C and/or 1901D
may or may not share the same architecture as computer system
1901A, and may be located in different physical locations.
The processor 1905 can include at least a microprocessor,
microcontroller, processor module or subsystem, programmable
integrated circuit, programmable gate array, digital signal
processor (DSP), or another control or computing device.
The storage media 1907 can be implemented as one or more
non-transitory computer-readable or machine-readable storage media.
Note that while in the embodiment of FIG. 19 the storage media 1907
is depicted as within computer system 1901A, in some embodiments,
the storage media 1907 may be distributed within and/or across
multiple internal and/or external enclosures of computing system
1901A and/or additional computing systems. Storage media 1907 may
include one or more different forms of memory including
semiconductor memory devices such as dynamic or static random
access memories (DRAMs or SRAMs), erasable and programmable
read-only memories (EPROMs), electrically erasable and programmable
read-only memories (EEPROMs) and flash memories; magnetic disks
such as fixed, floppy and removable disks; other magnetic media
including tape; optical media such as compact disks (CDs) or
digital video disks (DVDs); or other types of storage devices. Note
that the computer-executable instructions and associated data of
the analysis module(s) 1903 can be provided on one
computer-readable or machine-readable storage medium of the storage
media 1907, or alternatively, can be provided on multiple
computer-readable or machine-readable storage media distributed in
a large system having possibly plural nodes. Such computer-readable
or machine-readable storage medium or media is (are) considered to
be part of an article (or article of manufacture). An article or
article of manufacture can refer to any manufactured single
component or multiple components. The storage medium or media can
be located either in the machine running the machine-readable
instructions, or located at a remote site from which
machine-readable instructions can be downloaded over a network for
execution.
The computing system 1900 can also include one or more display
devices that are configured to display information produced by the
various tasks according to some embodiments, such as the tasks
described herein. For example, the display device can display plots
or other visual representations of the intensity data or spectra
produced by the various SPR sensor embodiments for human evaluation
of the data as desired.
It should be appreciated that computing system 1900 is only one
example of a computing system, and that computing system 1900 may
have more or fewer components than shown, may combine additional
components not depicted in the embodiment of FIG. 19, and/or
computing system 1900 may have a different configuration or
arrangement of the components depicted in FIG. 19. The various
components shown in FIG. 19 may be implemented in hardware,
software, or a combination of both hardware and software, including
one or more signal processing and/or application specific
integrated circuits.
Modifications
Although only a few examples have been described in detail above,
those skilled in the art will readily appreciate that many
modifications are possible in the examples without materially
departing from this subject disclosure.
In another example, an SPR sensor can perform measurements
utilizing monochromatic light at multiple wavelengths. In this
case, each wavelength probes a different distance into the SPR
sensing region, which can allow for determination of the thickness
of solid precipitation
Also, the methods and systems described herein are not limited to
analyzing a set of particular fluids. Various embodiments of
methods and systems described herein can be used to analyze
hydrocarbons (e.g., dark oils, heavy oils, volatile oils, and black
oils).
Furthermore, various embodiments of the present disclosure are not
limited to oil and gas field applications.
Also, the fluid handling elements (such as reservoirs, tanks,
pumps, valves and flow lines) of the SPR sensors as described
herein can be computer controlled or manually controlled to provide
for pressure control of the fluids flowing through the SPR sensor.
Furthermore, the temperature control elements of the SPR sensors as
described herein can be computer controlled or manually controlled
to provide for temperature control of the fluids flowing through
the SPR sensor.
Although several example embodiments have been described in detail
above, those skilled in the art will readily appreciate that many
modifications are possible in the example embodiments without
materially departing from the scope of this disclosure. Moreover,
the features described herein may be provided in any
combination.
Accordingly, all such modifications are intended to be included
within the scope of this disclosure as defined in the following
claims. In the claims, means-plus-function clauses are intended to
cover the structures described herein as performing the recited
function and not only structural equivalents, but also equivalent
structures. Thus, although a nail and a screw may not be structural
equivalents in that a nail employs a cylindrical surface to secure
wooden parts together, whereas a screw employs a helical surface,
in the environment of fastening wooden parts, a nail and a screw
may be equivalent structures. It is the express intention of the
applicant not to invoke 35 U.S.C. .sctn. 112, paragraph 6 for any
limitations of any of the claims herein, except for those in which
the claim expressly uses the words `means for` together with an
associated function.
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